424B4

424B4 1 d364234d424b4.htm 424B4 424B4

Filed pursuant to Rule 424(b)(4)
Registration No. 333-268424

PROSPECTUS

LOGO

TXO Energy Partners, L.P.

5,000,000 Common Units

Representing Limited Partner Interests

We are a Delaware limited partnership focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas and natural gas liquid reserves in North America. This is the initial public offering of our common units. No public market currently exists for our common units. We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act. We have been approved to list our common units on the New York Stock Exchange under the symbol “TXO.”

Investing in our common units involves risks. See “Risk Factors” beginning on page 28.

These risks include the following:

•

We may not have sufficient available cash to pay any quarterly distribution on our common units following the establishment of cash reserves and payment of expenses.

•

The volatility of oil, natural gas and NGL prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

•

Unless we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

•

We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost or feasibility of conducting our operations or expose us to significant liabilities.

•

Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.

•

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors, which could reduce the price at which our common units will trade.

•

Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution to our unitholders could be reduced.

•

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

PRICE $20.00 PER COMMON UNIT


	Per Common Unit		Total

Public offering price	$	20.00	$	100,000,000

Underwriting discount(1)	$	1.40	$	7,000,000


Proceeds, before expenses	$	18.60	$	93,000,000

(1)	Includes an aggregate structuring fee equal to 0.75% of the gross proceeds of this offering payable to Raymond James & Associates, Inc. Please read “Underwriting.

We have granted the underwriters a 30-day option to purchase up to an additional 750,000 common units on the same terms and conditions as set forth above if the underwriters sell more than 5,000,000 common units in this offering.

The underwriters expect to deliver the common units on or about January 31, 2023.

Joint Book-Running Managers


Raymond James		Stifel
Janney Montgomery Scott		Capital One Securities

January 26, 2023

TABLE OF CONTENTS



PROSPECTUS SUMMARY			1

TXO Energy Partners			1

Risk Factor Summary			7

Reorganization Transactions and Partnership Structure			10

Ownership and Organizational Structure of TXO Energy Partners			11

Management of TXO Energy Partners			12

Implications of Being an Emerging Growth Company			13

Principal Executive Offices and Internet Address			14

Summary of Conflicts of Interest and Duties			14

The Offering			16

Summary Historical and Pro Forma Financial and Operating Data			20

Non-GAAP Financial Measures			22

Summary of Reserve, Production and Operating Data			25

RISK FACTORS			28

Risks Related to Cash Distributions			28

Risks Related to Our Business and the Oil, Natural Gas and NGL Industry			29

Risks Related to Environmental and Regulatory Matters			48

Risks Inherent in an Investment in Us			58

USE OF PROCEEDS			76

CAPITALIZATION			77

DILUTION			78

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			79

General			79

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2021 and the Twelve Months Ended September 30, 2022			82

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2023			84

Assumptions and Considerations			87

Sensitivity Analysis			92

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			97

Distributions of Available Cash			97

Distributions of Cash Upon Liquidation			98

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA			99

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			102

BUSINESS AND PROPERTIES			129

MANAGEMENT			162

Management of TXO Energy Partners			162

Executive Officers and Directors of Our General Partner			163



Southland Bankruptcy			166

Reimbursement of Expenses of Our General Partner			166

Director Independence			167

Committees of the Board of Directors			167

EXECUTIVE COMPENSATION AND OTHER INFORMATION			170

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			175

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			177

Distributions and Payments to Our General Partner and Its Affiliates			177

Agreements with Affiliates in Connection with the Reorganization Transactions			178

Other Transactions with Related Persons			178

Procedures for Review, Approval or Ratification of Transactions with Related Persons			178

CONFLICTS OF INTEREST AND DUTIES			180

Conflicts of Interest			180

Duties of our General Partner			185

DESCRIPTION OF THE COMMON UNITS			189

The Units			189

Transfer Agent and Registrar			189

THE PARTNERSHIP AGREEMENT			191

Organization and Duration			191

Purpose			191

Limited Voting Rights			192

Applicable Law; Forum, Venue and Jurisdiction			193

Limited Liability			194

Issuance of Additional Partnership Interests			196

Amendment of the Partnership Agreement			196

Merger, Consolidation, Sale or Other Disposition of Assets			199

Termination and Dissolution			199

Liquidation and Distribution of Proceeds			200

Withdrawal or Removal of Our General Partner			200

Transfer of General Partner Interest			201

Transfer of Ownership Interests in Our General Partner			202

Election to be Treated as a Corporation			202

Change of Management Provisions			202

Limited Call Right			202

Meetings; Voting			203

Status as Limited Partner			203

Non-Citizen Unitholders; Redemption			204

Indemnification			204

Reimbursement of Expenses			205

Books and Reports			205

Right to Inspect Our Books and Records			205



Registration Rights			206

UNITS ELIGIBLE FOR FUTURE SALE			207

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES.			209

INVESTMENT IN TXO ENERGY PARTNERS BY EMPLOYEE BENEFIT PLANS			233

UNDERWRITING			235

VALIDITY OF THE COMMON UNITS			240

EXPERTS			240

WHERE YOU CAN FIND MORE INFORMATION			241

FORWARD-LOOKING STATEMENTS			242

INDEX TO FINANCIAL STATEMENTS			F-1

APPENDIX A - SEVENTH AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF TXO ENERGY PARTNERS			A-1

APPENDIX B - GLOSSARY OF OIL AND GAS TERMS			B-1

iii

Neither we nor the underwriters have authorized anyone to provide you with any information or to make any representations other than those contained in this registration statement. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should not assume that the information contained in this registration statement is accurate as of any date other than the date on the front cover of this registration statement. Our business, financial condition, results of operations and prospects may have changed since such dates. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

Until February 20, 2023 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

INDUSTRY AND MARKET DATA

The market data and certain other statistical information included in this prospectus are based on a variety of sources, including independent industry publications, government publications and other published independent sources. Some data is also based on our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Forward-Looking Statements” and “Risk Factors” in this prospectus.

TRADEMARKS AND TRADE NAMES

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. Because this is a summary, it may not contain all of the information that may be important to you and to your investment decision. The following summary is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this prospectus. You should read the entire prospectus carefully and should consider, among other things, the matters set forth in “Risk Factors,” “Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and unaudited pro forma consolidated financial statements, the Vacuum Properties historical statement of revenues and direct operating expenses and the related notes to each of those financial statements included elsewhere in this prospectus before deciding to invest in our common units.

The information presented in this prospectus assumes (i) the one-for-25.33 reverse split of the Company’s outstanding common units, to be effected immediately prior to the closing of this offering (the “Reverse Unit Split”) and (ii) that the underwriters do not exercise their option to purchase up to an additional 750,000 common units, unless otherwise indicated. As used in this prospectus, the term “our general partner” refers to TXO Energy GP, LLC, a Delaware limited liability company, and the terms “partnership,” the “Company,” “we,” “our,” “us” or similar terms refer to MorningStar Partners, L.P., to be renamed prior to the closing of this offering to TXO Energy Partners, L.P., a Delaware limited partnership (“TXO Energy Partners”) and its subsidiaries. We include a glossary of some of the oil and natural gas terms and other terms used in this prospectus in Appendix B. Our estimated proved reserve information included in this prospectus are based on reports prepared by our reservoir engineering staff and evaluated by Cawley, Gillespie & Associates, Inc., our independent reserve engineers.

TXO Energy Partners

Overview

We are focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas, and natural gas liquid reserves in North America. Our management team has significant industry experience acquiring and exploiting conventional oil and natural gas properties in multiple resource plays and basins. As a result of such experience, our operations focus primarily on enhancing the development and operation of producing properties through our concentration on efficiency and optimizing exploitation of current wells. Our current acreage positions are concentrated in the Permian Basin of West Texas and New Mexico and the San Juan Basin of New Mexico and Colorado, each of which we believe is characterized by low geologic risk, low decline rates and high recoveries relative to drilling and completion costs.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner which we refer to as “available cash”. We believe the low decline nature of our reserves and the relatively low cost to maintain production combined with our zero to low leverage profile will support distributions to our unitholders. The amount of cash available for distribution with respect to any quarter, however, will be dependent on the then-prevailing commodity prices. To mitigate the risk associated with volatile commodity prices and to further enhance the stability of our cash flow available for distributions, from time to time we may opportunistically hedge a portion of our production volumes at prices we deem attractive to mitigate our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales. Nevertheless, our quarterly cash distributions may vary from quarter to quarter as

a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero.

The members of our management team have an average of 32 years’ experience in the oil and gas industry and previously held executive roles at XTO Energy Inc. (“XTO”). Our management team has successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets for more than 30 years, completing hundreds of acquisitions totaling over $15 billion. Additionally, our Chief Executive Officer, Bob Simpson, has a greater than 45-year history in the oil and gas industry. Mr. Simpson founded Cross Timbers Oil company in 1986 (subsequently named XTO Energy) and served as Chief Executive Officer and Chairman over the life of the company, culminating with a sale to ExxonMobil Corporation (“Exxon”) for $41 billion in 2010. Additionally our management team has collectively invested more than $500 million in us since our inception. We believe our management team has the experience, expertise and commitment to create significant value for our unitholders in the form of cash distributions combined with growth in revenues and production. Certain members of our existing management team were acting or former officers of Southland Royalty Company LLC (“Southland”) when it voluntarily filed for Chapter 11 bankruptcy protection on January 27, 2020. Please see “Management—Southland Bankruptcy” for more information.

Information regarding performance by, or businesses associated with, TXO Energy Partners and its affiliates is presented for informational purposes only. Past performance by TXO Energy Partners and its affiliates, including our management team, is not a guarantee of future performance. You should not rely on the historical record of TXO Energy Partners and its affiliates or our management team’s prior performance as indicative of our future performance or the returns we will, or are likely to, generate going forward. Please read “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Past performance by our management team may not be indicative of future performance of an investment in us.”

As of December 31, 2021, our assets consisted of approximately 846,000 gross (370,000 net) leasehold and mineral acres located primarily in the Permian Basin and San Juan Basin. As of December 31, 2021, our total estimated proved reserves were approximately 130 MMBoe, of which approximately 37% were oil and approximately 82% were proved developed, both on a Boe basis. In the first nine months of 2022, we produced an average of approximately 23,265 Boe per day, approximately 70% of which came from assets operated by us.

The following tables present our historical estimated oil and natural gas reserves and PV-10 as of July 31, 2022. Our reserve data as of July 31, 2022 include the properties acquired as part of the Additional Interest Vacuum Acquisition described elsewhere in this prospectus.


	Estimated Proved Reserves as of July 31, 2022⁽¹⁾
	SEC Pricing Proved Developed Reserves (MBoe)⁽²⁾		SEC Pricing Proved Reserves (MBoe)		NYMEX Pricing Proved Developed Reserves (MBoe)⁽³⁾		NYMEX Pricing Proved Reserves (MBoe)⁽³⁾

Permian Basin		39,244.6		61,643.5		37,444.0		59,722.1

San Juan Basin		72,601.3		72,601.3		68,818.0		68,818.0

Other⁽⁴⁾		5,423.8		8,803.0		5,128.4		8,507.6


Total		117,269.7		143,047.8		111,390.4		137,047.7

(1)	Presented on an oil-equivalent basis using a conversion of six thousand cubic feet of natural gas to one stock tank barrel of oil. This conversion is based on energy equivalence and not on price or value equivalence.

(2)	SEC pricing, as required by the rules and regulations of the SEC, is the unweighted arithmetic average of the first-day-of-the-month price for each month within such period using published benchmark oil and gas prices, unless prices are defined by contractual arrangements.

(3)

Using NYMEX forward-month contract pricing in effect as of July 31, 2022. We have included this reserve sensitivity because we believe that the use of NYMEX forward-month prices provides investors with additional useful information about our reserves. For more information regarding our use of NYMEX Pricing, please see “—Summary of Reserve, Production and Operating Data—Summary of Reserves.”

(4)	Other includes reserves in various other locations in the United States, primarily in Utah and Mississippi.


	Estimated PV-10 as of July 31, 2022⁽²⁾
(in millions)	SEC Pricing Proved Developed PV-10⁽¹⁾		SEC Pricing Proved PV-10⁽³⁾		NYMEX Pricing Proved Developed PV-10⁽⁴⁾		NYMEX Pricing Proved PV-10⁽⁴⁾

Permian Basin	$	826.4	$	1,272.2	$	659.2	$	992.9

San Juan Basin	$	464.7	$	464.7	$	400.8	$	400.8

Other⁽⁵⁾	$	55.3	$	81.3	$	48.4	$	67.6


Total	$	1,346.4	$	1,818.2	$	1,108.4	$	1,461.3

(1)	SEC pricing, as required by the rules and regulations of the SEC, is the unweighted arithmetic average of the first-day-of-the-month price for each month within such period using published benchmark oil and gas prices, unless prices are defined by contractual arrangements.

(2)

(3)	Presented on an oil-equivalent basis using a conversion of six thousand cubic feet of natural gas to one stock tank barrel of oil. This conversion is based on energy equivalence and not on price or value equivalence.

(4)

(5)	Other includes reserves in various other locations in the United States, primarily in Utah and Mississippi.

The following table summarizes information regarding our active well count and development locations included in our reserve report as of July 31, 2022.


	As of July 31, 2022
	Active Oil and Natural Gas Wells				Active CO₂ Injection Wells				Conventional PUD Locations⁽¹⁾				Recomplete Locations⁽²⁾				Workover Locations⁽³⁾
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net

Permian Basin		3,912		685.3		55		39.1		233		108.7		51		32.8		23		22.6

San Juan Basin		11,509		1,093.8		—		—		—		—		—		—		—		—

Other⁽⁴⁾		3,025		88.4		—		—		4		1.8		—		—		—		—


Total		18,446		1,867.5		55		39.1		237		110.5		51		32.8		23		22.6

(1)	Approximately 97% of our wells are drilled conventionally. However, from time to time a small number of wells are horizontally completed.

(2)	Well locations we believe we can recomplete into another producing zone or zones.

(3)	Well locations where we believe a currently completed zone can be improved or restored by performing remedial workovers.

(4)	Other includes properties in various other locations in the United States, primarily in Utah and Mississippi.

Our Properties

Permian Basin

We acquired our initial 79,970 gross leasehold and mineral acres in the Permian Basin in 2012 and 2013. We subsequently acquired 11,929 additional gross leasehold acres through leasing and multiple bolt-on acquisitions. In November 2021, we acquired producing properties, including 24,052 gross leasehold acres and a CO₂ processing plant in the Permian Basin within New Mexico and CO₂ assets in Colorado (the “Vacuum Properties”) from Chevron Corporation (“Chevron”). In December 2021, we acquired additional producing properties, including 21,112 gross leasehold acres in the Permian Basin within Texas from Chevron (the “Andrews Parker Acquisition”). We refer to these together as the “2021 Acquisitions.” In August 2022 we acquired additional interests in our producing properties and a gas processing plant in the Permian Basin of New Mexico for approximately $52.6 million (the “Additional Interest Vacuum Acquisition”). As of September 30, 2022, we had 55 (gross) active CO₂ injection wells. Production from our CO₂ wells was 16.3 MMcf/d during the first nine months of 2022.

Our management team believes the development and exploitation of conventional assets in the Permian Basin is among the most economic oil and natural gas plays in the United States. Since completing the 2021 Acquisitions, we have focused our efforts on returning wells to production as well as on other low-risk maintenance projects. As we gain a greater understanding of these recently acquired assets, we expect to increase our drilling and recompletion work. Substantially all of our acreage in the Permian Basin is held by production, which means we do not have to drill any wells to maintain ownership of our leases. We drilled or participated in the drilling of 6 gross wells in the Permian Basin during 2022. Based on current commodity prices, we expect to drill or participate in the drilling of approximately 12 gross wells in 2023. We recompleted 13 gross wells in the Permian Basin in 2022 and expect to recomplete approximately 14 gross wells in 2023. We returned 12 gross wells to production in the Permian Basin in 2022 and expect to return 9 gross wells in 2023. Our decline rate for our Permian Basin properties over the next 12 months is currently estimated to be approximately 7%.

San Juan Basin

We acquired our initial 175,376 gross leasehold and mineral acres in the San Juan Basin in 2012 and 2013. We subsequently acquired 273,187 additional gross leasehold and mineral acres in June 2020.

Our San Juan acreage includes substantial, predictable, low-decline natural gas production that provides for relatively stable cash flows. Our decline rate for our San Juan Basin properties over the next 12 months is currently estimated to be approximately 10%. Our existing production comes from primarily coalbed methane wells, in which we own 363,358 gross acres. Substantially all of our acreage in the San Juan Basin is held by production. Additionally, we own 85,205 gross acres in New Mexico in the Mancos Shale. We believe our Mancos Shale properties offer us significant potential upside that is held by production.

We drilled or participated in the drilling of 18 gross wells in the San Juan Basin during 2022. Based on current commodity prices, we expect to drill or participate in the drilling of approximately 22 gross wells in 2023. We did not recomplete any wells in the San Juan Basin in 2022 and do not expect to recomplete any wells in the San Juan Basin in 2023. We returned 5 gross wells to production in the San Juan Basin in 2022 and expect to return none in 2023.

For the nine months ended September 30, 2022, our consolidated revenues were derived 48% from oil revenues, 40% from natural gas revenues and 12% from NGL revenues, in each case excluding the unrealized effects of our commodity derivative contracts. After giving effect to unrealized commodity derivative contracts, our revenues were derived 59% from oil revenues, 27% from natural gas revenues and 14% from NGL revenues over the same period. For the nine months ended September 30, 2022, our total average production was 23,265 Boe/d (approximately 25% oil, 59% natural gas, and 16% NGLs). Over the same period, our average production in the Permian Basin was 7,046 Boe/d (approximately 82% oil, 5% natural gas, and 13% NGLs) and our average production in the San Juan Basin was 14,841 Boe/d (approximately 1% oil, 81% natural gas, and 18% NGLs).

Development Plan and Capital Budget

Historically, our business plan has focused on acquiring and then exploiting producing assets. Funding sources for our acquisitions have included proceeds from bank borrowings, cash from our partners and cash flow from operating activities. Our development budget was approximately $30.0 million for 2022 and is approximately $30.0 million for 2023. Much of our development time and capital is spent on workovers, recompletions and field optimizations of existing assets. We expect to use the additional information derived from this exploitation to inform our decisions about additional drilling opportunities to pursue, either in recently acquired assets or new acquisitions. However, over the next 24 months we anticipate that approximately half of our development activity will be focused on drilling new wells, virtually all of which we expect to be conventional, vertical wells.

During 2022, we spent approximately $20 million to drill 21 gross wells (8 net wells) and on related equipment, $6 million on recompletions of existing wells and $2 million on remedial workovers and other maintenance projects. We spent approximately $13 million in the Permian Basin and approximately $15 million in the San Juan Basin in 2022.

We expect to allocate the majority of our 2023 budget to projects focused on enhancing existing production. Based on current commodity prices and our drilling success rate to date, we

expect to be able to fund our 2023 capital development programs from cash flow from operations and the net proceeds of this offering. We increased our 2021 capital program to $8.1 million compared to $5.5 million in 2020, primarily in response to the improved oil price environment and the improving global and national economic environment.

Our Business Strategies

Our primary business objective is to make increasing distributions to our unitholders over time. To achieve our objective, we intend to execute the following business strategies:

•

Focus on long-lived, low decline conventional assets. We believe that by focusing on the exploitation of our existing assets, we can maintain current production using a portion of our operating cash flow, while utilizing the remainder of our operating cash flow to acquire additional assets to exploit and make distributions to our unitholders.

•

Maximize ultimate hydrocarbon recovery from our assets through enhancement and optimization of producing properties. We continuously seek efficiencies in our drilling, completion and production techniques to optimize ultimate resource recoveries, rates of return and cash flows. We will continue to work to unlock additional value and will allocate capital towards next generation technologies where applicable. In addition, we intend to take advantage of under-development in basins where we operate by expanding our geologic investigation of additional producing horizons on our acreage and adjacent acreage. We seek to expand our development beyond our known productive areas to add reserves to our inventory at attractive all-in costs.

•

Focus on making cash distributions to, and providing long term value for, our unitholders. Our primary goal is to maximize investor returns through cash distributions and flat to low production and reserves growth over time.

•

Maintain financial flexibility with a conservative capital structure and ample liquidity. We intend to conduct our operations primarily through cash flow generated from operations with a focus on maintaining a disciplined balance sheet with little to no outstanding debt. Due to our strong operating cash flows and liquidity, we have substantial flexibility to fund our capital budget and to potentially accelerate our drilling program as conditions warrant. Our focus is on the economic extraction of hydrocarbons while maintaining a prudent leverage ratio and strong liquidity profile. Although we may use leverage to make accretive acquisitions, we will do so with the long-term goal of remaining substantially debt free. Further, we expect that our hedging strategy will reduce our exposure to commodity price volatility.

•

Execute attractive acquisitions and optimize assets through effective integration. Our management team has a history of successfully identifying, acquiring and optimizing assets over the past three decades. We believe our acreage positions in the Permian Basin and San Juan Basin provide opportunities to increase production and reserves through the implementation of mechanical and operational improvements, workovers, behind-pipe completions, secondary and tertiary recovery operations, new development wells and other

development activities. We plan to use the expertise of our management team to strategically acquire properties that complement our operations.

Our Strengths

We believe that the following strengths will allow us to successfully execute our business strategies:

•

Experienced and personally invested management team with an extensive track record of value creation. We believe our management team’s significant industry experience is a distinguishing competitive advantage. The members of our management team have an average of 32 years’ experience in the oil and gas industry and have previously held executive roles at XTO. Our management team has successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets for more than 30 years. Members of our management team have collectively personally invested more than $500 million in us since our inception.

•

Stable, long-lived, conventional asset base with low production decline rates. The majority of our interests are in properties that have produced oil and natural gas for decades. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present lower risk than unconventional resource plays. Our assets are characterized by long-lived reserves with low production decline rates, a stable development cost structure and low-geologic risk developmental drilling opportunities with predictable production profiles. For example, our decline rate over the next twelve months is currently estimated to be approximately 9%.

•

Ability to source, integrate and optimize acquisitions. Our management team has demonstrated the ability to source and integrate acquisitions of various sizes. While at XTO, our management team completed hundreds of acquisitions for over $15 billion in consideration and successfully integrated such acquisitions, ultimately driving significant returns for shareholders. We have successfully drawn on this experience to identify and complete multiple acquisitions to establish our anchor positions in the Permian Basin and San Juan Basin, including our recent 2021 Acquisitions. We expect that our expertise in sourcing and completing acquisitions will allow us to successfully execute additional bolt-on acquisitions in our existing operating areas and, if and when appropriate, additional opportunistic acquisitions.

•

Conservatively capitalized balance sheet, strong liquidity profile and financial flexibility. We have a strong and conservative financial position that allows us to effectively allocate capital and grow our reserves and production. Due to the significant existing vertical production and the predictable low-decline profiles associated with our existing production, our business generates significant operating cash flows. After this offering, we expect to have little to no debt and substantial liquidity, which will provide us with further financial flexibility to fund our capital expenditures and grow production and reserves as part of our existing strategic plan. We may also opportunistically hedge to protect our future operating cash flows from volatility in commodity prices.

Risk Factor Summary

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units, among other things. You should carefully consider the risks described in “Risk Factors” and the other information in this

prospectus before investing in our common units. Some of the most significant challenges and risks we face include the following:

Risks Related to Cash Distributions

•

We may not have sufficient available cash to pay any quarterly distribution on our common units following the establishment of cash reserves and payment of expenses.

•

The assumptions underlying the forecast of cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results.

Risks Related to Our Business and the Oil, Natural Gas and NGL Industry

•

The volatility of oil, natural gas and NGL prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

•

If commodity prices decline and remain depressed for a prolonged period, production from a significant portion of our properties may become uneconomic and cause downward adjustments of our reserve estimates and write downs of the value of such properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.

•

Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our business, financial condition, results of operations and cash distributions to unitholders.

•

We operate certain of our properties through a joint venture over which we have shared control.

•

Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition.

•

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, or the threat thereof, could have a material adverse effect on our business, liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our common units.

•

We use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.

•

Our Credit Facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

•

Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Risks Related to Environmental and Regulatory Matters

•

Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil, natural gas and NGL exploration and production activities, and reduce demand for the oil, natural gas and NGLs we produce.

Risks Inherent in an Investment in Us

•

Our partnership agreement replaces our general partner’s fiduciary duties to us and our unitholders with contractual standards governing its duties, and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

•

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain non-citizen unitholders.

•

Our unitholders have limited voting rights and are not entitled to elect our general partner or the Board, which could reduce the price at which our common units will trade.

•

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

•

Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

•

Control of our general partner may be transferred to a third party without unitholder consent.

•

Our general partner may elect to convert or restructure us from a partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent.

•

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval.

•

The NYSE does not require a publicly traded partnership like us to comply, and we do not intend to comply, with certain of its governance requirements generally applicable to corporations.

Tax Risks to Common Unitholders

•

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Reorganization Transactions and Partnership Structure

Each of the following transactions have occurred or will occur immediately prior to the closing of this offering:

•

on October 1, 2022, all of MorningStar Partners, L.P.’s outstanding Series 3 preferred units automatically converted into 270,831 common units, and, effective as of October 1, 2022, all of MorningStar Partner, L.P.’s outstanding Series 3 warrants were exercised for 81,249 common units;

•

we will cause the exchange of all of MorningStar Partners, L.P.’s outstanding Series 5 preferred units for 10,235,081 common units, resulting in our capital structure following such transactions to consist of a single class of common units;

•

holders of our common units, which include Bob R. Simpson, our Chief Executive Officer and Chairman of the Board, Brent W. Clum, our President of Business Operations, Chief Financial Officer and Director, Keith A. Hutton, our President of Production and Development and Director, Scott T. Agosta, our Chief Accounting Officer, Vaughn O. Vennerberg II, our former President, and Timothy L. Petrus, our former Executive Vice President and all other limited partners party to our amended and restated agreement of limited partnership (collectively, the “Existing Owners”) will contribute all of the outstanding equity interests in us to a new parent company, MorningStar Partners II, L.P., a Delaware limited partnership (“MSP II”), in exchange for equity interests in MSP II;

•

we will amend our governing documents to, among other things, (i) change our name to “TXO Energy Partners, L.P.” and (ii) reflect TXO Energy GP, LLC, a Delaware limited liability company, as our new non-economic general partner; and

•

we will effectuate the one-for-25.33 Reverse Unit Split.

Except where specified otherwise, the disclosure in this prospectus gives effect to the reorganization transactions as set forth above, which we refer to as the Reorganization Transactions.

Ownership and Organizational Structure of TXO Energy Partners

The diagram below depicts our organization and ownership before giving effect to the offering and the Reorganization Transactions.

LOGO

The diagram below depicts our organization and ownership after giving effect to the offering and the Reorganization Transactions and assumes that the underwriters do not exercise their option to purchase additional common units.

LOGO

Management of TXO Energy Partners

We are managed and operated by the board of directors (the “Board”) and executive officers of our general partner, TXO Energy GP, LLC. Our unitholders will not be entitled to elect our general partner or its directors or otherwise participate in our management or operations. For information about the executive officers and directors of our general partner, please read “Management.”

The sole member of our general partner is MorningStar Oil & Gas, LLC (“MSOG”), all of the ownership interests of which are owned by Bob R. Simpson, our Chief Executive Officer and Chairman of the Board, Brent W. Clum, our President of Business Operations, Chief Financial Officer and Director, Keith A. Hutton, our President of Production and Development and Director, and Vaughn O. Vennerberg II, our former President, which we refer to as our Founders. As a result, the Founders control our general partner and will be entitled to appoint its entire board of directors. Our Existing Owners include the Founders as well as all other parties that currently hold limited partner interests in us.

Our operations are conducted through, and our assets are currently owned by, various subsidiaries. Although all of the employees that conduct our business are either employed by our general partner or its subsidiaries, we sometimes refer to these individuals in this prospectus as our employees.

We conduct a substantial amount of our operations through Cross Timbers Energy, LLC (“Cross Timbers”), a joint venture owned 50% by us and 50% by certain affiliates of Exxon and XTO, which we refer to collectively as the “XTO Entities.” We account for our undivided interest in our investment in Cross Timbers using the proportionate consolidation method, pursuant to which we consolidate our proportionate share of assets (including reserves), liabilities, revenues and expenses of the joint venture. In accordance with the limited liability company agreement governing Cross Timbers (the “JV LLCA”), Cross Timbers is managed by us and governed by a member management committee comprised of six members, three of whom are appointed by us and three of whom are appointed by the XTO Entities.

Implications of Being an Emerging Growth Company

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:

•

provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act;

•

provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations nor more than two years of selected financial data;

•

comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; or

•

provide certain disclosure regarding executive compensation required of larger public companies required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”).

We will cease to be an emerging growth company upon the earliest of:

•

the last day of the fiscal year in which we have $1.235 billion or more in annual revenues (as such amount may be adjusted by the SEC for inflation);

•

the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30 of such year);

•

the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

•

the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. We have elected to avail ourselves of the provision of the JOBS Act that permits emerging growth companies to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. As a result, we will not be subject to new or revised accounting standards at the same time as other public companies that are not emerging growth companies. We intend to take advantage of the other exemptions discussed above, both in this prospectus and in future filings with the U.S. Securities and Exchange Commission (the “SEC”). Accordingly, the information contained herein and that we provide to our unitholders from time to time may be different than the information you receive from other public companies. For additional information, see the section titled “Risk Factors—Risks Inherent in an Investment in Us—Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our common units less attractive to investors.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 400 W 7th St., Fort Worth, TX 76102 and our telephone number at that address is (817) 334-7800. Our website address is www.txoenergy.com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is not adverse to our best interests. However, because our general partner is wholly owned by MSOG, in certain cases the officers and directors of our general partner also have a duty to manage the business of our general partner at the direction of MSOG, which is owned by the Founders. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including the Founders, on the other hand. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flow necessary to make cash distributions to our unitholders, including determinations related to:

•

purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that may also be suitable for the Founders or any affiliate of the Founders;

•

the manner in which our business is operated;

•

the level of our borrowings;

•

the amount, nature and timing of our capital expenditures; and

•

the amount of cash reserves necessary or appropriate to satisfy our general, administrative and other expenses and debt service requirements and to otherwise provide for the proper conduct of our business.

For a more detailed description of the conflicts of interest and duties of our general partner, please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

Our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including any common units held by our general partner and its affiliates). Upon consummation of this offering, our general partner will continue to be controlled by the Founders, who will own and control the voting of an aggregate of approximately 27% of our outstanding common units. Assuming that we do not issue any additional common units and the Founders do not transfer their common units, the Founders will have the ability to significantly influence any amendment to our partnership agreement, including our policy to distribute all of our available cash to our unitholders. Please see “Risk Factors—Risks Inherent in an Investment in Us” and “The Partnership Agreement—Amendment of the Partnership Agreement.”

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the duties owed and remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including the Founders and their affiliates, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—Duties of Our General Partner” for a description of the duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

The Offering

Common units offered by us

5,000,000 common units representing limited partner interests (5,750,000 common units if the underwriters exercise in full their option to purchase additional common units).

Units outstanding after this offering

30,000,000 common units representing limited partner interests in us (30,750,000 common units if the underwriters exercise their option in full to purchase additional common units).

Use of proceeds

We intend to use the expected net proceeds of approximately $88.0 million from this offering ($102.0 million if the underwriters exercise their option to purchase additional units in full), based upon the initial public offering price of $20.00 per common unit, after deducting underwriting discounts and estimated expenses, to repay a portion of the amounts outstanding under our revolving credit facility (our “Credit Facility”).

Cash distributions

Within 60 days after the end of each quarter (other than the fourth quarter) and within 90 days after the end of the fourth quarter, beginning with the quarter ending March 31, 2023, we expect to pay distributions of our available cash to unitholders of record on the applicable record date.

The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay such cash distributions is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We will prorate the amount of our distribution payable for the period from the closing of this offering through March 31, 2023, based on the actual length of that period.

Our partnership agreement generally provides that we will distribute all available cash each quarter to the holders of common units, pro rata.

Pro forma cash available for distribution generated during the year ended December 31, 2021 and the twelve month period ended September 30, 2022 was approximately $89.6 million

and $133.0 million, respectively. As a result, for the year ended December 31, 2021, we would have generated available cash sufficient to pay a cash distribution of $0.75 per unit per quarter ($2.99 on an annualized basis) and for the twelve month period ended September 30, 2022, we would have generated cash sufficient to pay a cash distribution of $1.11 per unit per quarter ($4.43 on an annualized basis). For a calculation of our ability to pay distributions to our unitholders based on our pro forma results for the year ended December 31, 2021 and twelve month period ended September 30, 2022, please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Available Cash for the Year Ended December 31, 2021 and the Twelve Months Ended September 30, 2022.”

We believe, based on our financial forecast and the related assumptions included under “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2023,” that we will have sufficient cash available for distribution to make cash distributions of $3.75 per unit on all common units for the four quarters ending September 30, 2023. We will not have a minimum quarterly distribution nor is there any guarantee that we will make any particular amount of distributions or any distributions to our unitholders in any quarter. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Issuance of additional units

We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Partnership Interests.”

Limited voting rights

Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²⁄₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, the affiliates of the general partner (including the Founders) will own an aggregate of approximately 38% of our common units and, therefore, will be able to prevent the removal of

our general partner. Please read “The Partnership Agreement—Limited Voting Rights.”

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon consummation of this offering, affiliates of our general partner (including the Founders) will own an aggregate of approximately 38% of our common units (excluding any common units purchased by our officers and directors under our directed unit program). Please read “The Partnership Agreement—Limited Call Right.”

Election to be treated as a corporation

Eligible Holders and redemption

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain non-citizen unitholders.

We have the right (which we may assign to any of our affiliates), but not the obligation, to redeem all of the common units of any holder that is not an Eligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the then-current market price of the common units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by

our general partner. Please read “Description of the Common Units—Transfer Agent and Registrar—Transfer of Common Units” and “The Partnership Agreement—Non-Citizen Unitholders; Redemption.”

Estimated ratio of taxable income to distributions

We estimate that if our unitholders own the common units purchased in this offering through the record date for distributions for the period ending December 31, 2025, such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 75% of the cash distributed to such unitholders with respect to that period. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” for the basis of this estimate.

Material tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences.”

Directed Unit Program

At our request, the underwriters have reserved for sale, at the initial public offering price, up to 10% of the common units being offered by this prospectus for sale to our directors, executive officers and to certain individuals identified by us. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read “Underwriting—Directed Unit Program.”

Listing and trading symbol

We have been approved to list our common units on the NYSE under the symbol “TXO.”

Summary Historical and Pro Forma Financial and Operating Data

The summary historical consolidated financial data set forth below as of and for each of the years ended December 31, 2021 and 2020 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated financial data set forth below as of September 30, 2022 and for the nine months ended September 30, 2022 and 2021 are derived from our unaudited financial statements and related notes included elsewhere in this prospectus.

The summary unaudited pro forma financial data as of September 30, 2022 and for the nine months ended September 30, 2022 and the year ended December 31, 2021 are derived from the unaudited pro forma condensed financial statements of TXO Energy Partners included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:

•

the acquisition of producing properties and a gas processing plant in the Permian Basin in New Mexico and CO₂ assets in Colorado from Chevron in November 2021, which we refer to as the Vacuum Properties;

•

the Reorganization Transactions as described in “—Reorganization Transactions and Partnership Structure” elsewhere in this prospectus summary, including the one-for-25.33 Reverse Unit Split; and

•

the issuance and sale by us to the public of 5,000,000 common units in this offering and the application of the net proceeds as described in “Use of Proceeds.”

The unaudited pro forma financial data were prepared as if the items listed above occurred on January 1, 2021, in the case of statement of operations data, or September 30, 2022, in the case of balance sheet data. We have not given pro forma effect to the Andrews Parker Acquisition, the Additional Interest Vacuum Acquisition or to the incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership.

The unaudited pro forma historical financial data are presented for illustrative purposes only and are not necessarily indicative of the financial position that would have existed or the financial results that would have occurred if this offering and the acquisition of the Vacuum Properties had been consummated on the dates indicated, nor are they necessarily indicative of the financial position or results of our operations in the future. The pro forma adjustments, as described in the notes to the unaudited pro forma condensed combined financial statements, are preliminary and based upon currently available information and certain assumptions that our management believes are reasonable. The summary historical consolidated financial data are qualified in their entirety by, and should be read in conjunction with, the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included in this prospectus and the consolidated financial statements and related notes and other financial information included in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information. Historical results are not necessarily indicative of results that may be expected for any future period.

You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our historical combined financial statements and our unaudited pro forma condensed financial statements and the notes thereto included elsewhere in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information.

The following table presents non-GAAP financial measures, Adjusted EBITDAX and cash available for distribution, which we use in evaluating the financial performance of our business. These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain these measures below and reconcile them to the most directly comparable financial measures calculated and presented in accordance with GAAP.


	TXO Energy Partners Historical										TXO Energy Partners Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,				Year Ended December 31			Nine Months Ended September 30,
	2021			2020			2022		2021		2021			2022
(in thousands, except per unit amounts)	(unaudited)

Statement of Operations Data:

Revenues:

Oil and condensate	$	69,971		$	59,070		$	120,703	$	40,061	$	118,186		$	120,703

Natural gas liquids	$	27,875		$	8,660		$	29,268	$	18,086	$	29,810		$	29,268

Natural gas	$	130,498		$	41,034		$	54,067	$	80,783	$	130,676		$	54,067


Total revenues⁽¹⁾	$	228,344		$	108,764		$	204,038	$	138,930	$	278,672		$	204,038


Expenses:

Production	$	69,256		$	49,146		$	93,961	$	45,833	$	99,406		$	93,961

Exploration	$	124		$	55		$	281	$	81	$	124		$	281

Taxes, transportation and other	$	58,040		$	27,509		$	72,993	$	37,941	$	63,102		$	72,993

Depreciation, depletion and amortization	$	39,889		$	42,322		$	30,329	$	28,054	$	47,650		$	30,329

Impairment	$	—		$	134,097		$	—	$	—	$	—		$	—

Accretion of discount on asset retirement obligations	$	4,670		$	3,940		$	4,508	$	3,513	$	4,962		$	4,508

General and administrative	$	12,175		$	6,995		$	572	$	3,646	$	12,175		$	572


Total expenses	$	184,154		$	264,064		$	202,644	$	119,068	$	227,419		$	202,644


Operating income (loss)	$	44,190		$	(155,300	)	$	1,394	$	19,862	$	51,253		$	1,394


Other income (expenses):

Other income	$	14,139		$	72		$	18,677	$	9,128	$	17,312		$	18,677

Interest income	$	16		$	194		$	68	$	11	$	16		$	68

Interest expense	$	(5,870	)	$	(8,204	)	$	(5,526)	$	(3,722)	$	(3,923	)	$	(3,032	)


Total other income (expenses)	$	8,285		$	(7,938	)	$	13,219	$	5,417	$	13,405		$	15,713


Net income (loss)	$	52,475		$	(163,238	)	$	14,613	$	25,279	$	64,658		$	17,107


Net income per limited partner unit:

Basic	$	2.10		$	(6.53	)	$	0.58	$	1.01	$	2.16		$	0.57


Diluted	$	2.10		$	(6.53	)	$	0.58	$	1.01	$	2.12		$	0.56


Weighted average number of limited partner units outstanding:

Basic		25,000			25,000			25,000		25,000		30,000			30,000


Diluted		25,000			25,000			25,000		25,000		30,545			30,545


	TXO Energy Partners Historical												TXO Energy Partners Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,						Year Ended December 31		Nine Months Ended September 30,
	2021			2020			2022			2021			2021		2022
(in thousands, except per unit amounts)	(unaudited)

Other Financial Data:

Adjusted EBITDAX	$	85,348		$	32,322		$	118,628		$	52,530		$	103,637	$	118,628

Cash available for distribution	$	72,348		$	20,132		$	105,538		$	40,610		$	92,586	$	108,032

Cash Flow Data:

Net cash provided by (used in):

Operating activities	$	73,726		$	18,964		$	103,668		$	47,000

Investing activities	$	(227,801	)	$	(16,718	)	$	(70,443	)	$	(21,415	)

Financing activities	$	139,689		$	14,067		$	(29,624	)	$	(35,089	)

Balance Sheet Data (at period end):

Total assets	$	832,820		$	623,940		$	901,855		$	611,037				$	901,855

Total long-term debt	$	152,100		$	151,252		$	132,100		$	107,100				$	44,100

Partners’ capital	$	541,359		$	303,268		$	549,492		$	327,937				$	637,492

(1)	Includes the effect of unrealized losses on commodity derivatives.

Non-GAAP Financial Measures

Adjusted EBITDAX

We include in this prospectus the non-GAAP financial measure Adjusted EBITDAX and provide our calculation of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDAX as net income (loss) before (1) interest income, (2) interest expense, (3) depreciation, depletion and amortization, (4) impairment expenses, (5) accretion of discount on asset retirement obligations, (6) exploration expenses, (7) unrealized (gains) losses on commodity derivative contracts, (8) non-cash incentive compensation, (9) non-cash (gain) loss on forgiveness of debt and (10) certain other non-cash expenses.

Adjusted EBITDAX is used as a supplemental financial measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to more effectively evaluate our operating performance and our results of operation from period to period and against our peers without regard to financing methods, capital structure or historical cost basis. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX is not a measurement of our financial performance under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as indicators of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should

not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies.

Cash Available for Distribution

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial measure used by our management and by external users of our financial statements, such as investors, lenders and others (including industry analysts and rating agencies who will be using such measure), to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as Adjusted EBITDAX less net cash interest expense, exploration expense, non-recurring (gain) / loss and development costs. Development costs includes all of our capital expenditures made for oil and gas properties, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances. Cash available for distribution is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by or used in operating activities as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measures most directly comparable to cash available for distribution are net income and net cash provided by operating activities. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities.

Reconciliations of Adjusted EBITDAX and Cash Available for Distribution to GAAP Financial Measures

The following table presents our reconciliation of the non-GAAP financial measures Adjusted EBITDAX and cash available for distribution to the GAAP financial measures of net income (loss) and net cash provided by operating activities, as applicable, for each of the periods indicated.


	TXO Energy Partners Historical												TXO Energy Partners Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,						Year Ended December 31			Nine Months Ended September 30,
	2021			2020			2022			2021			2021			2022
(in thousands)	(unaudited)

Net income (loss)	$	52,475		$	(163,238	)	$	14,613		$	25,279		$	64,658		$	17,107

Interest expense	$	5,870		$	8,204		$	5,526		$	3,722		$	3,923		$	3,032

Interest income	$	(16	)	$	(194	)	$	(68	)	$	(11	)	$	(16	)	$	(68	)

Depreciation, depletion and amortization	$	39,889		$	42,322		$	30,329		$	28,054		$	47,650		$	30,329

Impairment expenses		—		$	134,097			—			—			—			—

Accretion of discount on asset retirement obligations	$	4,670		$	3,940		$	4,508		$	3,513		$	4,962		$	4,508

Exploration expense	$	124		$	55		$	281		$	81		$	124		$	281

Non-cash derivative (gain) / loss	$	(8,977	)	$	2,887		$	63,416			—		$	(8,977	)	$	63,416


	TXO Energy Partners Historical												TXO Energy Partners Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,						Year Ended December 31			Nine Months Ended September 30,
	2021			2020			2022			2021			2021			2022
(in thousands)	(unaudited)

Non-cash incentive compensation	$	2,400		$	4,227			—			—		$	2,400			—

Non-cash (gain) on forgiveness of debt	$	(9,152	)		—			—		$	(9,152	)	$	(9,152	)		—

Non-recurring (gain) / loss	$	(1,935	)	$	22		$	23		$	1,044		$	(1,935	)		23


Adjusted EBITDAX	$	85,348		$	32,322		$	118,628		$	52,530		$	103,637		$	118,628


Cash interest expense	$	(4,520	)	$	(7,340	)	$	(5,012	)	$	(3,160	)	$	(2,571	)	$	(2,518	)

Cash interest income	$	16		$	194		$	68		$	11		$	16		$	68

Exploration expense	$	(124	)	$	(55	)	$	(281	)	$	(81	)	$	(124	)	$	(281	)

Non-recurring (gain)/loss	$	—		$	—		$	—		$	(1,044	)	$	—		$	—

Development costs⁽¹⁾	$	(8,372	)	$	(4,989	)	$	(7,865	)	$	(7,646	)	$	(8,372	)	$	(7,865	)


Cash Available for Distribution	$	72,348		$	20,132		$	105,538		$	40,610		$	92,586		$	108,032


Net cash provided by operating activities	$	73,726		$	18,964		$	103,668		$	47,000

Changes in operating assets and liabilities	$	6,994		$	6,157		$	9,735		$	1,256

Development costs⁽¹⁾	$	(8,372	)	$	(4,989	)	$	(7,865	)	$	(7,646	)


Cash Available for Distribution	$	72,348		$	20,132		$	105,538		$	40,610

⁽¹⁾	Development costs includes all of our capital expenditures made for oil and gas properties, other than acquisitions.

Reconciliation of PV-10 to Standardized Measure.

Our PV-10 has historically been computed on the same basis as our standardized measure of discounted future net cash flows (“Standardized Measure”), the most comparable measure under GAAP, but does not include a provision for either future well abandonment costs or the Texas gross margin tax. PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of either well abandonment costs or income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. See below for a reconciliation of the Proved Reserves PV-10 value to the Standardized Measure, the most directly comparable GAAP measure.

The following table provides a reconciliation of our Proved Reserves PV-10 value to the Standardized Measure at December 31, 2021:


	TXO Energy Partners
	As of December 31, 2021 SEC Pricing

(In millions)

Proved Reserves PV-10 value	$	1,022.2

Present value of future asset retirement obligations discounted at 10%	$	(33.6	)

Present value of future income taxes discounted at 10% . .	$	(2.0	)


Standardized Measure	$	986.6

Summary of Reserve, Production and Operating Data

The following tables summarize our estimated oil, natural gas and NGL reserves as of July 31, 2022 and December 31, 2021 and our production and historical operating data for the year ended December 31, 2021. The information included in these tables is based on reserve reports prepared by our independent consulting petroleum engineers, Cawley, Gillespie & Associates, Inc. For more information regarding our reserve volumes and values, see “Business and Properties—Oil, Natural Gas and NGL Data—Reserves” and our reserve reports filed as exhibits to the registration statement of which this prospectus forms a part. Historical reserve volumes and values are not necessarily indicative of results that may be expected for any future period.

Summary of Reserves

Our historical SEC reserves, PV-10 and Standardized Measure were calculated using oil and gas price parameters established by current SEC guidelines, including the use of an average effective price, calculated as prices equal to the 12-month unweighted arithmetic average of the first day of the month prices for each of the preceding 12 months as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”). These prices were adjusted for differentials on a per-property basis, which may include local basis differential, treating cost, transportation, gas shrinkage, gas heating value and/or crude quality and gravity corrections. All prices are held constant throughout the lives of the properties. Our estimated proved NYMEX reserves and PV-10 as of July 31, 2022 were prepared using average annual NYMEX forward-month contract pricing in effect as of July 31, 2022 (“NYMEX Pricing”) but is otherwise presented on the same basis as the reserve information prepared in accordance with SEC regulations. Our reserve data as of July 31, 2022 include the properties acquired as part of the Additional Interest Vacuum Acquisition described elsewhere in this prospectus.


	TXO Energy Partners
			As of July 31, 2022
	As of December 31, 2021 SEC Pricing(1)		SEC Pricing(1)		NYMEX Pricing(3)

Proved Developed:

Oil (MBbls)		30,207.9		34,336.1		32,737.1

Natural gas (MMcf)		353,214.9		379,768.1		360,522.5

Natural gas liquid (MBbls)		17,434.2		19,638.9		18,566.3

Oil equivalent (MBoe)		106,511.3		117,269.7		111,390.4

PV-10 (in millions)(2)	$	772.2	$	1,346.4	$	1,108.4

Proved Undeveloped:

Oil (MBbls)		18,397.7		20,366.8		20,262.1

Natural gas (MMcf)		26,061.0		24,867.7		24,843.3

Natural gas liquid (MBbls)		593.4		1,266.7		1,254.6

Oil equivalent (MBoe)		23,334.6		25,778.1		25,657.3

PV-10 (in millions)(2)	$	250.0	$	471.8	$	352.9

Total Proved:

Oil (MBbls)		48,605.6		54,702.9		52,999.2

Natural gas (MMcf)		379,275.9		404,635.8		385,365.8

Natural gas liquid (MBbls)		18,027.6		20,905.6		19,820.9

Oil equivalent (MBoe)		129,845.9		143,047.8		137,047.7

Standardized Measure (in millions)(2)	$	986.6		—		—

PV-10 (in millions)(2)	$	1,022.2	$	1,818.2	$	1,461.3

(1)

Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $66.56 per barrel for oil and $3.60 per MMBtu for natural gas at December 31, 2021 and $88.54 per barrel for oil and $5.36 per MMBtu for natural gas at July 31, 2022. The base prices were based upon Henry Hub and WTI-Cushing spot prices, respectively. These base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these net adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $64.76 per barrel for oil, $19.62 per barrel for NGLs and $2.31 per Mcf for natural gas for the year ended December 31, 2021 and $86.89 per barrel for oil, $24.95 per barrel for NGLs and $3.76 per Mcf for natural gas for the twelve months ended July 31, 2022.

(2)

(3)

The NYMEX futures prices as of July 31, 2022 used to prepare our reserve report are shown in the following table. These base prices were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these net adjustments, the net realized prices for the NYMEX futures price case over the life of the proved properties was estimated to be $71.51 per barrel for oil, $21.99 per barrel for NGLs and $3.20 per Mcf for natural gas.


	2022		2023		2024		2025		2026		Thereafter

Natural gas price (per MMBtu)	$	8.36	$	5.63	$	4.66	$	4.50	$	4.40	$	4.40

Oil price (per Bbl)	$	94.92	$	86.49	$	79.38	$	74.64	$	71.02	$	71.02

(4)

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Our PV-10 has historically been computed on the same basis as our Standardized Measure, the most comparable measure under GAAP, but does not include a provision for either future well abandonment costs or the Texas gross margin tax. PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of either well abandonment costs or income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

Select Production and Operating Statistics

The following table summarizes our oil, natural gas and NGL production and historical operating data for the periods presented.


	TXO Energy Partners
	Year Ended December 31,		Nine Months Ended September 30,
	2021		2022

Net Production Volumes:

Oil (MBbl)		1,033		1,605

Natural Gas (MMcf)		30,590		22,522

NGLs (MBbl)		1,089		993

Total (MBoe)		7,220		6,351

Average daily production (MBoe per day)		20		23

Average Wellhead Realized Prices (before giving effect to derivatives):

Oil ($/Bbl)	$	67.41	$	98.27

Natural Gas ($/Mcf)	$	4.00	$	6.32

NGLs ($/Bbl)	$	25.16	$	37.94

Average Wellhead Realized Prices (after giving effect to derivatives):

Oil ($/Bbl)	$	67.74	$	75.22

Natural Gas ($/Mcf)	$	4.27	$	2.40

NGLs ($/Bbl)	$	25.60	$	29.47

Operating costs and expenses (per Boe):

Production	$	9.59	$	14.79

Taxes, transportation, and other	$	8.04	$	11.49

Depreciation, depletion, amortization and accretion	$	5.52	$	4.78

General and administrative expenses	$	1.69	$	0.09

RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. Additionally, new risks may emerge at any time and we cannot predict those risks or estimate the extent to which they may affect financial performance

If any of the following risks actually occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.

Risks Related to Cash Distributions

We may not have sufficient available cash to pay any quarterly distribution on our common units following the establishment of cash reserves and payment of expenses.

We may not have sufficient available cash each quarter to pay distributions on our common units. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including development, optimization and exploitation of our oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. The amount of available cash that we distribute to our unitholders will depend principally on the cash we generate from operations, which will depend on, among other factors:

•

the amount of oil, natural gas and NGLs we produce;

•

the prices at which we sell our oil, natural gas and NGL production;

•

the amount and timing of settlements on our commodity derivative contracts;

•

the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;

•

the level of our operating costs, including payments to our general partner and its affiliates for general and administrative expenses; and

•

the level of our interest expenses, which will depend on the amount of our outstanding indebtedness and the applicable interest rate.

Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

Our management’s forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending September 30, 2023. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from those forecasted. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual distribution or any distribution on our common units, which may cause the market price of our common units to decline materially.

The amount of our quarterly cash distributions from our available cash, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution and could pay no distribution with respect to any particular quarter.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our future business performance may be volatile, and our cash flows may be unstable. We will not have a minimum quarterly distribution. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Risks Related to Our Business and the Oil, Natural Gas and NGL Industry

The volatility of oil, natural gas and NGL prices due to factors beyond our control greatly affects our financial condition, results of operations and cash available for distribution.

Our revenues, operating results, cash available for distribution and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil, natural gas and NGLs. Prices for oil, natural gas and NGLs are subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors beyond our control. These factors include, but are not limited to:

•

worldwide and regional economic conditions impacting the supply and demand for oil, natural gas and NGLs;

•

the level of global oil and natural gas exploration and production;

•

political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

•

the ability of and actions taken by members of Organization of the Petroleum Exporting Countries (“OPEC”) and other oil-producing nations in connection with their arrangements to maintain oil prices and production controls;

•

the impact on worldwide economic activity of an epidemic, outbreak or other public health events, such as COVID-19;

•

the proximity, capacity, cost and availability of gathering and transportation facilities;

•

localized and global supply and demand fundamentals;

•

weather conditions across the globe;

•

technological advances affecting energy consumption and energy supply;

•

speculative trading in commodity markets, including expectations about future commodity prices;

•

the proximity of our natural gas, NGL and oil production to, and capacity, availability and cost of, natural gas pipelines and other transportation and storage facilities, and other factors that result in differentials to benchmark prices;

•

the impact of energy conservation efforts;

•

the price and availability of alternative fuels;

•

stockholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas to minimize the emission of greenhouse gases;

•

domestic, local and foreign governmental regulation and taxes; and

•

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Changes in oil, natural gas and NGL prices have a significant impact on the amount of oil, natural gas and NGL that we can produce economically, the value of our reserves and on our cash flows. Historically, oil, natural gas and NGL prices and markets have been volatile, and those prices and markets are likely to continue to be volatile in the future. In particular, oil prices fluctuated during 2018 and 2019, and declined dramatically during 2020 due to demand collapse caused by COVID-19 and associated lockdowns, dropping to ($37.63) per barrel of crude WTI oil on April 20, 2020. During the year ended December 31, 2021, the NYMEX daily oil price reached a high of $84.65 per Bbl in October 2021 and experienced a low of $47.62 in January 2021, and the NYMEX daily natural gas price reached a high of $23.86 per MMBtu in February 2021 and experienced a low of $2.43 in April 2021, and prices have remained volatile. In 2022, partially in response to the conflict in Ukraine, the NYMEX daily oil price reached a high of $123.70 on March 8, 2022 before declining in the second half of the year, with a price of $80.26 as of December 30, 2022, and the NYMEX daily natural gas price reached a high of $9.85 on August 22, 2022 and has declined since, with a price of $4.48 as of December 30, 2022. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations and cash available for distribution.

We may be unable to pay quarterly distributions to our unitholders without substantial capital expenditures that maintain our asset base. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors.

Our future reserves and production and, therefore, our cash flow and ability to make distributions are highly dependent on our success in efficiently developing, optimizing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.

Significantly lower commodity prices over extended periods of time may render many of our development projects uneconomic and result in a downward adjustment of our reserve estimates, which would negatively impact our borrowing base and ability to borrow to fund our operations or make distributions to our unitholders. As a result, we may reduce the amount of distributions paid to our unitholders or cease paying distributions. In addition, a significant or sustained decline in commodity prices could hinder our ability to effectively execute our hedging strategy. For example, during a period of declining commodity prices, we may enter into commodity derivative contracts at relatively unattractive prices in order to mitigate a potential decrease in our borrowing base upon a redetermination.

Furthermore, as a result of a lower net commodity price environment for some of our oil and natural gas assets, in 2020 we recorded an impairment of $133.2 million on certain of our long-lived assets in the New Mexico Permian Basin, $0.2 million on our assets in East Texas and $0.7 million on our unproved properties primarily in the Texas Permian Basin. Prior to 2020, our historical impairment of proved properties included $177.4 million of proved property impairments from 2014 through 2018. Due to the improvement in commodity pricing environment and industry conditions, we did not record any impairments in 2021. However, if commodity prices fall below certain levels, our production, proved reserves and cash flows will be adversely impacted and we may be required to record additional impairments, which could be material. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which may be determined at the discretion of our lenders. See “—Any significant reduction in the borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.”

Currently, our producing properties are concentrated in the Permian and San Juan Basins, making us vulnerable to risks associated with operating in a limited number of geographic areas.

As a result of our geographic concentration, adverse industry developments in our operating areas could have a greater impact on our financial condition and results of operations than if we were more geographically diverse. We may also be disproportionately exposed to the impact of regional supply and demand factors, governmental regulations or midstream capacity constraints. Delays or interruptions caused by such adverse developments could have a material adverse effect on our financial condition and results of operations.

Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and

production activities are increasing, as has recently been the case in our operating areas, we are subject to increasing competition for drilling rigs, workover rigs, tubulars and other well equipment, services, supplies as well as increased labor costs and a decrease in qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months and, in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.

Our future financial condition and results of operations, and therefore our ability to make cash distributions to our unitholders, will depend on the success of our acquisition, development, optimization and exploitation activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable production.

Our decisions to purchase, develop, optimize or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•

unexpected or adverse drilling conditions;

•

delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements including permitting requirements, limitations on or resulting from wastewater discharge and the disposal of exploration and production wastes, including subsurface injections;

•

elevated pressure or irregularities in geological formations;

•

shortages of or delays in obtaining equipment and qualified personnel;

•

facility or equipment failures or accidents;

•

lack of available gathering facilities or delays in construction of gathering facilities;

•

lack of available capacity on interconnecting transmission pipelines;

•

adverse weather conditions, such as hurricanes, lightning storms, flooding, tornadoes, snow or ice storms and changes in weather patterns;

•

issues related to compliance with, or changes in, environmental and other governmental regulations;

•

environmental hazards, such as oil and natural gas leaks, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•

declines in oil, natural gas and NGL prices;

•

the availability and timely issuance of required governmental permits and licenses; and

•

title defects or legal disputes regarding leasehold rights.

We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our growth potential.

Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in cash available for distribution. There is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition, do so on commercially acceptable terms or obtain sufficient financing to do so. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

In addition, our Credit Facility imposes certain limitations on our ability to enter into mergers or combination transactions and to make certain investments. Our Credit Facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement.”

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to successfully integrate the acquired businesses and assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential liabilities, including, but not limited to, environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or may acquire in the future may not produce as projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from any seller for liabilities arising from or attributable to the period prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Increased costs of capital could adversely affect our business.

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. For example, since March 2022, the Federal Reserve has raised its target range for the federal funds rate six times, including by 50 basis points in May 2022 and December 2022, and by 75 basis points in each of June 2022, July 2022, September 2022 and November 2022. Furthermore, additional rate hikes are likely to occur for the foreseeable future, as indicated by the minutes of the Federal Open Markets Committee. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.

Drilling locations that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.

We may in the future explore potential drilling locations in areas where we currently own properties and in other areas. These potential drilling locations would be in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively, prior to drilling, whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil, natural gas or NGLs exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our other identified drilling locations. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Because of these uncertain factors, we do not know if the potential well locations we have identified, or will identify, will ever be drilled or if we will be able to produce oil, natural gas and NGLs from these or any other potential locations. As such, our actual drilling activities may materially differ from those presently identified.

Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other interest

in a specific mineral interest. The existence of a material title deficiency can render a lease or other interest worthless and can adversely affect our results of operations and financial condition. The failure of title on a lease, in a unit or any other mineral interest may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

We operate certain of our properties through a joint venture over which we have shared control.

We conduct certain of our operations through Cross Timbers, a joint venture owned 50% by us and 50% by certain affiliates of Exxon and XTO, which we refer to collectively as the “XTO Entities.” For the year ended December 31, 2021, our interest in Cross Timbers represented approximately 41% of our revenues and approximately 35% of our proved reserves.

In accordance with the limited liability company agreement governing Cross Timbers, or the “JV LLCA”, Cross Timbers is managed by us and governed by a member management committee comprised of six members, three of whom are appointed by us and three of whom are appointed by the XTO Entities. The JV LLCA requires that certain matters, including certain material contracts or acquisitions, mergers, sale of substantially all assets or other change of control transactions, and transfers of our interest to a third party, be approved by unanimous consent of the voting members of the management committee and therefore such actions require the approval of the XTO Entities. Our ability to make distributions to our unitholders depends in part on the performance of this entity and its ability to distribute funds to us. We face certain risks associated with shared control, and the XTO Entities may at any time have economic, business or legal interests or goals that are inconsistent with ours.

We own non-operating interests in properties developed and operated by third parties and some of our leasehold acreage could be pooled by a third-party operator. As a result, we are unable, or may become unable as a result of pooling, to control the operation and profitability of such properties.

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other contractual arrangements. Similarly, our acreage in Colorado, Texas and New Mexico may be pooled by third-party operators under state law. If our acreage is involuntarily pooled under state forced pooling statutes, it would reduce our control over such acreage and we could lose operatorship over a portion of our acreage that we plan to develop.

We may not be able to maximize the value associated with acreage that we own but do not operate in the manner we believe appropriate, or at all. We cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our business, financial condition and results of operations.

Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.

The majority of the scientific community has concluded that climate change may result in more frequent and/or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our development, optimization and exploitation activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes, thunderstorms, tornadoes and snow or ice storms, or other climate-related events such as wild fires, in each case which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions and events could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary resources, such as water, and third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2022, due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.2% in September 2022. As of December 31, 2022, inflation was at 6.5%. Though we incorporated inflationary factors into our 2022 business plan, inflation has outpaced those original assumptions. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services. Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs for the nine months ended September 30, 2022 compared to the same period in 2021. We also may face shortages of these commodities and labor, which may prevent us from executing our development plan. These supply chain constraints and inflationary pressures will likely continue to adversely impact our operating costs and, if we are unable to manage our supply chain, it may impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could impact our ability to distribute available cash and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

We continue to take actions to mitigate supply chain and inflationary pressures. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical suppliers which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient.

In addition, continued hostilities related to the Russian invasion of Ukraine and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors and other factors, such as another surge in COVID-19 cases or decreased demand from China, combined with volatile commodity prices, and declining business and consumer confidence may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our business, financial condition and results of operations.

We face risks related to epidemics, outbreaks or other public health events, or the threat thereof, that are outside of our control, and could significantly disrupt our business and operational plans and adversely affect our liquidity, financial condition, results of operations, cash flows and ability to pay distributions on our common units. The COVID-19 pandemic has adversely affected the global economy and has resulted in unprecedented governmental actions in the United States and countries around the world, including, among other things, social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs. Additionally, the effects of the COVID-19 pandemic might worsen the likelihood or the impact of other risks already inherent in our business. We believe that the known and potential impacts of the COVID-19 pandemic and related events include, but are not limited to, the following:

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disruption in the demand for oil, natural gas and other petroleum products;

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intentional project delays until commodity prices stabilize;

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potentially higher borrowing costs in the future;

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a need to preserve liquidity, which could result in a reductions, delays or changes in our capital expenditures;

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liabilities resulting from operational delays due to decreased productivity resulting from stay-at-home orders affecting our workforce or facility closures resulting from the COVID-19 pandemic;

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future asset impairments, including impairment of our natural gas properties, oil properties, and other property and equipment; and

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infections and quarantining of our employees and the personnel of vendors, suppliers and other third parties.

New variants of the virus could cause further commodity market volatility and resulting financial market instability, or any other event described above. These are variables beyond our control and may adversely impact our business, financial condition and results of operations.

We use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.

We periodically enter into futures contracts, energy swaps, options, collars and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas and natural gas liquids sales. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Derivatives.” By using derivative instruments to economically hedge exposure to changes in commodity prices, we could limit the benefit we would receive from increases in the prices for oil and natural gas, which could have an adverse effect on our financial condition. Likewise, to the extent our production is not hedged, we are exposed to declines in commodity prices, and our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in commodity prices.

Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil, NGL and natural gas revenues. Settlements of derivatives are included in cash flows from operating activities. While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under GAAP, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements. For example, for the nine months ended September 30, 2022, revenues increased $65.1 million to $204.0 million from $138.9 million for the nine months ended September 30, 2021 and the increase was primarily attributable to an increase in production of 1,180 MBoe primarily as a result of additional production from the acquired Vacuum properties of 957 MBoe and Andrews Parker properties of 253 Mboe, respectively. These increases were partially offset by losses on our hedging activity of $133.7 million, of which $63.4 million were unrealized losses and $70.3 million were realized losses.

Additionally, our Credit Facility may hinder our ability to effectively execute our hedging strategy. We are allowed to hedge at most 90% of reasonably anticipated projected production, but we were required to hedge at least 75% of reasonably anticipated projected production of proved developed producing reserves for the 12-month period following January 1, 2022. However, as of any time, if the net leverage ratio (the ratio of total net debt-to-EBITDAX) is less than or equal to 1.0 to 1.0 and the cash and cash equivalents on hand are equal to or greater than 20% of the borrowing base then in effect, the minimum required hedge volume for month one through month 24 will be reduced to 50%. We were in compliance with all financial and other covenants of the Credit Facility as of March 31, 2022 except the covenant regarding hedge volumes required as of March 31, 2022. We received a waiver for this exception in June, 2022. We were in compliance with all covenants in our Credit Facility, except the covenant regarding hedge volumes required as of September 30, 2022. We received a waiver for this exception in September 2022. This waiver, which will continue through the next scheduled redetermination in March 2023, allows us to reduce the hedging requirement from 30 months to 18 months beginning January 1, 2023 and from 50% to 45% of the reasonably anticipated projected production. See “—Our Credit Facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement.”

We also expose ourselves to credit risk resulting from the failure of the counterparty to perform under the terms of the applicable derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make

it unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

The process of estimating oil, natural gas and NGL reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

Furthermore, SEC rules require that, subject to limited exceptions, PUD reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule may limit our potential to record additional PUD reserves as we pursue our drilling program. To the extent that natural gas and oil prices become depressed or decline materially from current levels, such condition could render uneconomic a number of our identified drilling locations, and we may be required to write down our PUD reserves if we do not drill those wells within the required five-year time frame. If we choose not to develop PUD reserves, or if we are not otherwise able to successfully develop them, then we will be required to remove the associated volumes from our reported proved reserves.

The preparation of reserve estimates requires the projection of production rates and the timing of development expenditures based on an analysis of available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

The present value of future net cash flow from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. For example, our estimated proved reserves as of December 31, 2021 were calculated under SEC rules using the unweighted arithmetic average first day of the month prices for the prior 12 months of $3.60/MMBtu for natural gas and $66.56/Bbl for oil at December 31, 2021, which, for certain periods during this period, were substantially different from the available spot prices. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with

Accounting Standards Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

We depend upon several significant purchasers for the sale of most of our oil, natural gas and NGL production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

For the year ended December 31, 2021, Phillips 66 Company, Tenaska Marketing and Eco-Energy, Inc. accounted for more than 40% of our total revenues, excluding the impact of our commodity derivatives. For the year ended December 31, 2020, Phillips 66 Company and Tenaska Marketing accounted for more than 40% of our total revenues, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our revenue during such periods. We do not have long-term contracts with our customers; rather, we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers. The loss of any one of these purchasers, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties—Operations—Marketing and Customers.”

The availability of a ready market for any hydrocarbons we produce depends on numerous factors beyond our control, including, but not limited to, the extent of domestic production and imports of oil, the proximity and capacity of natural gas and NGL pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGLs sold in interstate commerce.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

The oil and natural gas industry is intensely competitive, and we compete with companies that possess and employ financial, technical and personnel resources substantially greater than ours. Our ability to acquire additional properties and to exploit reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.

Our Credit Facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

Our Credit Facility restricts, among other things, our ability to:

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incur certain liens or permit them to exist;

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merge or consolidate with another company;

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incur or guarantee additional debt;

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make certain investments and acquisitions;

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make or pay distributions on, or redeem or repurchase, common units, if an event of default or borrowing base deficiency exists;

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enter into certain types of transactions with affiliates; and

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transfer, sell or otherwise dispose of assets.

In addition, our Credit Facility will require us to comply with customary financial covenants and specified financial ratios, including that we maintain (i) a current ratio greater than 1.0 to 1.0 and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.00 to 1.00. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our Credit Facility that are not cured or waived within specific time periods, our lender may declare our indebtedness thereunder to be immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. Any such acceleration of such debt could also result in a cross-acceleration of other future indebtedness which we may incur. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Credit Facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our Credit Facility, the lenders could seek to foreclose on our assets or force us to seek bankruptcy protection.

In addition, our Credit Facility may hinder our ability to effectively execute our hedging strategy. Our Credit Facility limits the maximum percentage of our production that we can hedge and the duration of those hedges, so we may be unable to enter into additional commodity derivative contracts during favorable market conditions and, thus, unable to lock in attractive future prices for our product sales. Conversely, our Credit Facility also requires us to hedge a minimum percentage of our production, which may cause us to enter into commodity derivative contracts at inopportune times. For example, during a period of declining commodity prices, we may enter into commodity derivative contracts at relatively unattractive prices in order to mitigate a potential decrease in our borrowing base upon a redetermination.

Any significant reduction in the borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our Credit Facility limits the amount we can borrow up to a borrowing base amount. The administrative agent under our Credit Facility determines our borrowing base based on the value of our oil and natural gas properties. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. As of November 3, 2022, the last date of redetermination, our borrowing base was $165 million. Such amount will be redetermined semi-annually on or before each March 15 and September 1 and will depend on the volumes of our proved oil and natural gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Credit Facility, including our business, financial condition and debt obligations, the types of reserves, the value and effect of hedge contracts then in effect and the effect of gas imbalances. In addition, our lenders will have flexibility to reduce our borrowing base due to subjective factors. Our next borrowing base redetermination is scheduled for March 2023.

In the future, we may not be able to access adequate funding under our Credit Facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lenders to meet their funding obligations. Declines in commodity prices could result in a determination by the lenders to decrease the borrowing base in the future and, in such a case, we could be required to promptly repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our Credit Facility, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If oil, natural gas and NGL prices decline for an extended period of time, we may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional equity or debt capital or restructure or refinance indebtedness or seek bankruptcy protection to facilitate a restructuring. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt or preferred equity arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition in certain circumstances. We may not be able to consummate these dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may prevent us from meeting scheduled debt service obligations.

Our level of indebtedness may increase and reduce our financial flexibility.

Although we do not expect to have any indebtedness at the closing of this offering, we may incur significant indebtedness, whether through future debt issuances or by drawing down on the availability under our Credit Facility, in the future in order to make acquisitions or to develop our properties or for other general corporate purposes. Such indebtedness could affect our operations in several ways:

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a significant portion of our cash flows could be used to service our indebtedness;

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a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

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the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay distributions on our common units and make certain investments;

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a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

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our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and our industry;

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a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a significant portion of our then-outstanding bank borrowings; and

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a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, or other general corporate purposes.

A high level of indebtedness, if incurred in the future, increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness in such event depends on our future performance. General economic conditions, commodity prices, and financial, business, and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings, or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our common units or a refinancing of our debt include financial market conditions (including any financial crisis), the value of our assets, and our performance at the time we need capital.

Our drilling and production programs may not be able to obtain access to truck transportation, pipelines and storage facilities, natural gas gathering facilities, and other transportation, processing and refining facilities to market our oil, natural gas and NGL production, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.

The marketing of oil, natural gas and NGL production depends in large part on the capacity and availability of trucks, pipelines and storage facilities, natural gas gathering systems and other transportation, processing and refining facilities. In order to market new or increased production, new facilities or expanded capacity on existing facilities may be required. Access to transportation, processing, and refining facilities, whether new or existing, is, in many respects, beyond our control. If these facilities are unavailable to us because we are unable to obtain services on commercially reasonable terms, the owners and operators of such facilities are unable to obtain permits for new or expanded capacity in compliance with environmental and other governmental or regulatory requirements or are delayed in obtaining such permits, or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell our oil, natural gas and NGL production.

Increases in activity in our operating areas could, in the future, contribute to bottlenecks in processing and transportation that could negatively affect our results of operations, and these adverse effects could be disproportionately severe to us compared to our more geographically diverse competitors. As a result, our business, financial condition and results of operations could be adversely affected.

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flows and ability to complete development activities as planned.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for experienced development crews and oil field equipment and services and materials as drilling activity increases; and increased taxes, which could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our cash available for distribution to our unitholders. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

We are highly dependent on the services of our senior management and the loss of senior management or technical personnel could adversely affect our operations.

We depend on the services of our senior management and technical personnel. Our management team has an average of 32 years’ experience in the oil and gas industry. There can be no assurance that we would be able to replace such members of management with comparable replacements or that such replacements would integrate well with our existing team. Further, the loss of the services of our senior management could have a material adverse effect on our business, financial condition and results of operations. In particular, the loss of the services of one or more members of our management team could disrupt our operations. We do not maintain, nor do we plan to obtain, “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

Our continued success will depend, in part, on our ability to attract and retain experienced technical personnel, including geologists, engineers and other professionals. Large numbers of technical personnel in the oil and gas industry are approaching the normal retirement age of 65 or have otherwise accepted an early retirement during the COVID-19 pandemic. These and other factors may lead to a shortage of qualified, entry-level technical personnel and increased compensation costs. The foregoing factors may lead to additional competition from oil and gas companies attempting to meet their hiring needs. If a shortage of technical personnel materializes, companies in the oil and gas industry may be unable to hire adequate numbers of technical personnel to meet their needs, resulting in disruptions, increased costs of operations, financial difficulties and other adverse effects, and these circumstances may become more severe in the future and thereby cause a material adverse effect on our business.

Past performance by our management team may not be indicative of future performance of an investment in us.

performance. You should not rely on the historical record of TXO Energy Partners and its affiliates or our management team’s prior performance as indicative of our future performance or the returns we will, or are likely to, generate going forward.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease our cash available for distribution.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease our cash available for distribution. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.

Asset retirement obligations for our oil and gas assets and properties are estimates, and actual costs could vary significantly.

We are required to record a liability for the discounted present value of our estimated asset retirement obligations to plug and abandon inactive wells and related assets and non-producing oil and gas properties in which we have a working interest. Such asset retirement obligations may include complete structural removal and/or restoration of the land. At December 31, 2021, we had accrued asset retirement obligations of $104.5 million. Although management has used its best efforts to determine future asset retirement obligations, assumptions and estimates can be influenced by many factors beyond management’s control, including, but not limited to, changes in regulatory requirements, which may be more restrictive in the future, changes in costs for abandonment related services and technologies, which could increase or decrease based on supply and demand, and/or extreme weather conditions, such as hurricanes and lightning storms, which may cause structural or other damage to oil and natural gas assets and properties. Accordingly, our estimate of future asset retirement obligations could differ materially from actual costs that may be incurred.

Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil, natural gas and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected

information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. Although we maintain insurance to protect against losses resulting from certain data protection breaches and cyber-attacks, our coverage for protecting against such risks may not be sufficient.

In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period, and our systems and insurance coverage for protecting against such cybersecurity risks may be costly and may not be sufficient. As cyber-attackers become more sophisticated, we may be required to expend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, and we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

We are subject to a number of privacy and data protection laws, rules and directives (collectively, data protection laws) relating to the processing of personal data.

The regulatory environment surrounding data protection laws is uncertain. Varying jurisdictional requirements could increase the costs and complexity of compliance with such laws, and violations of applicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other penalties that could materially harm our business and reputation.

Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, an inability to find, produce, process and sell oil, natural gas and NGLs and an inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Our acquisition, development, optimization and exploitation projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.

The oil, natural gas and NGL industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition, development, optimization and exploitation of oil and natural gas reserves. Funding sources for our capital expenditures have included proceeds from bank borrowings, cash from our partners and cash flow from operating activities. Our management has collectively invested more than $500 million in us since our inception. Following the completion of this offering, we expect that we will not be able to rely on

our management or our partners for capital and will need to utilize the public equity or debt markets and bank financings to fund acquisitions and capital expenditures. We expect to fund our 2023 capital expenditures with cash generated by operations; however, our cash flows from operations and access to capital are subject to a number of variables, including:

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our proved reserves;

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the volume of hydrocarbons we are able to produce from existing wells;

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the prices at which our production is sold;

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our ability to acquire, locate and produce new reserves;

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the extent and levels of our derivative activities;

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the levels of our operating expenses; and

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our ability to borrow under our Credit Facility.

If our revenues or the borrowing base under our Credit Facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. Even if we can obtain debt financing on terms acceptable to us, the issuance of additional indebtedness would require that a portion of our cash flows from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions. Additionally, the market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. The issuance of additional equity securities may be dilutive to our unitholders. If cash flows generated by our operations or the proceeds from this offering are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Continuing political and social concerns about the issues of climate change may result in changes to our business and significant expenditures, including litigation-related expenses.

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect our business. Governmental and other entities in various United States states, such as California and New York, have filed lawsuits against coal, gas oil and petroleum companies. These suits allege damages for contributions to, or failure to disclose the impact of, climate change, and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions both in the United States and globally. Though we are not currently a party to any such lawsuit, these suits present uncertainty regarding the extent to which companies engaged in oil and gas production face an increased risk of liability stemming from climate change, which risk would also adversely impact the oil and gas industry

and impact demand for our services. The ultimate outcome and impact to us of any such litigation cannot be predicted with certainty, and we could incur substantial legal costs associated with defending any potential similar lawsuits in the future.

Risks Related to Environmental and Regulatory Matters

Our operations are subject to numerous stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and the protection of the environment and natural resources (including threatened and endangered species). These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting drilling and other regulated activities; the restriction of types, quantities and concentration of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations, and reclamation and restoration costs. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. We may not be able to recover some or any of these costs from insurance. The trend in environmental regulation has been towards more stringent requirements, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. For example, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple sites into a single source for air quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements.

In October 2015, the EPA issued a new lower National Ambient Air Quality Standard (“NAAQS”) for ozone of 70 parts per billion. In 2017, the EPA designated certain counties in

southeastern New Mexico and West Texas located in the Permian Basin attainment/unclassifiable for the 2015 ozone NAAQS. However, in June 2022, EPA announced that it is considering a discretionary redesignation for these counties based on current monitoring data and other air quality factors. If the Permian Basin counties in which we operate were redesignated as nonattainment areas, this could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs.

The EPA has also imposed increasingly stringent performance standards on oil and gas operations. In 2016, the EPA issued regulations under NSPS OOOOa that require operators to reduce methane and volatile organic compound (“VOC”) emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector. The proposed rule would establish standards of performance for sources that commence construction, modification or reconstruction after the date the proposed rule was published in the Federal Register and would establish emissions guidelines, which will inform state plans to establish standards for existing sources. The EPA issued a supplemental proposed rule in November 2022 to update, strengthen and expand its November 2021 proposed rule. The supplemental proposed rule would impose more stringent requirements on the oil and natural gas industry, and is expected to be finalized in 2023. The Bureau of Land Management (“BLM”) also issued a proposed rule in November 2022 to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. State agencies have similarly imposed increasing restrictions on emissions from oil and gas operations. For example, in 2022, the New Mexico Environment Department adopted new regulations establishing emission reduction requirements for storage vessels, compressors, turbines, heaters, engines, dehydrators, pneumatic devices, produced water management units, and other equipment and processes. Compliance with these more stringent standards and other environmental regulations at the federal or state levels could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant. See “Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us.

Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005 (“EPAct 2005”), the Federal Energy Regulatory Commission (the “FERC”) has civil penalty authority under the Natural Gas Act of 1938 (“NGA”) to impose penalties for current violations of $1,388,496 per violation per day. The FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission (“FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1,323,791 per violation per day, and the Commodity Futures Trading Commission (“CFTC”) prohibits market manipulation in the markets regulated by the CFTC, including similar anti manipulation authority with respect to swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to

the greater of $1,303,559 or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Natural Gas Industry.”

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas (“GHG”) emissions constitute a pollutant under the Clean Air Act (the “CAA”), the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the Department of Transportation (the “DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal government has also increased regulation of methane from oil and gas facilities in recent years. For example, in 2016, the EPA issued regulations under NSPS OOOOa that require operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector. The proposed rule would establish standards of performance for sources that commence construction, modification or reconstruction after the date the proposed rule was published in the Federal Register and would establish emissions guidelines, which will inform state plans to establish standards for existing sources. The EPA issued a supplemental proposed rule in November 2022 to update, strengthen and expand its November 2021 proposed rule. The supplemental proposed rule would impose more stringent requirements on the oil and natural gas industry, and is expected to be finalized in 2023. The BLM also issued a proposed rule in November 2022 to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. If finalized, these increasingly stringent methane and VOC requirements on new facilities, or the application of new requirements to existing facilities, could result in additional restrictions on our operations and increased compliance costs, which could be significant. Additionally, the Inflation Reduction Act, recently passed by Congress and signed into law by President Biden, imposes several new requirements on oil and gas operators, including a fee for leaks or venting of methane, starting at $900 per ton in 2024 and rising to $1,500 per ton in 2026, from certain facilities. The act also appropriates significant federal funding for renewable energy initiatives. These developments may make it harder for the oil and gas industry to attract capital. Given the long-term trend toward increasing regulation, we expect there will be additional future federal GHG regulations of the oil and gas industry.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, the New Mexico Oil Conservation Commission has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on

the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO₂ GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. President Biden also agreed that same month to cooperate with Chinese leader Xi Jinping on accelerating progress toward the adoption of clean energy. The impact of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time. However, to the extent these developments result in new restrictions on oil and gas operations, increase operational costs, or otherwise reduce the demand for oil and gas, they could have a material adverse effect on our business.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has issued several executive orders focused on addressing climate change, including items that may impact our costs to produce, or demand for, oil and gas. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO₂ GHG emissions, such as methane and nitrous oxide. The Biden Administration is also considering revisions to the leasing and permitting programs for oil and gas development on federal lands.

Litigation risks are also increasing, as a number of entities have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer protection laws, alleging that companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Various U.S. financial regulators have announced that they are considering climate-related regulations and, separately, the Federal Reserve has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

Additionally, the SEC has proposed new rules relating to the disclosure of a range of climate-related risks. The proposed rule contains several new disclosure obligations, including (i) disclosure on an annual basis of a registrant’s scope 1 and scope 2 greenhouse gas emissions, (ii) third-party independent attestation of the same for accelerated and large accelerated filers, (iii) for some registrants, disclosure on an annual basis of a registrant’s scope 3 greenhouse gas emissions for accelerated and large accelerated filers, (iv) disclosure on how the board of directors and management oversee climate-related risks and certain climate-related governance items, (v) disclosure of information related to a registrant’s climate-related targets, goals and/or transitions plans and (vi) disclosure on whether and how climate-related events and transition activities impact line items above a threshold amount on a registrant’s consolidated financial statements, including the impact of the financial estimates and the assumptions used. While we would likely be subject to the longer proposed phase-in for the reporting requirements as an emerging growth company, we are currently assessing this rule and cannot predict the costs of implementation or any potential adverse impacts resulting from the rule should it be adopted as proposed; however, we expect these costs to be substantial. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.

The adoption and implementation of new or more stringent international, federal, regional or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas. Additionally, international, federal, regional or state legislation, regulation or other initiatives could make alternative forms of energy more attractive in comparison to oil and natural gas, and thereby reduce demand for oil and natural gas. Moreover, political, litigation and financial risks may result in our restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.

Increased attention to ESG matters and conservation measures may adversely impact our business.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG initiatives and disclosures, and consumer demand for alternative forms of energy may result in increased costs, including, but not limited to, increased costs related to compliance, stakeholder engagement, contracting and insurance, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on the price of our common units and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters in the future, many of the statements in those voluntary disclosures may be on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach

to identifying and measuring many ESG matters. Such disclosures may also be partially reliant on third-party information that we have not or cannot independently verify. In addition, we expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters, and increased regulation will likely to lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor.

In addition, organizations that voluntarily provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investments to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact our suppliers or customers, which may adversely impact our business, financial condition, or results of operations.

We may face various risks associated with the long-term trend toward increased activism against oil and gas exploration and development activities.

Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil and gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling and hydraulic fracturing in the United States, even in jurisdictions that are among the most stringent in their regulation of the industry. Future activist efforts could result in the following:

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delay or denial of drilling permits;

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shortening of lease terms and reduction in lease size;

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restrictions on installation or operation of production, gathering or processing facilities;

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restrictions on the use of certain operating practices, such as hydraulic fracturing, or disposal of related waste materials, such as hydraulic fracking fluids and production;

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increased severance and/or other taxes;

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cyber-attacks;

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legal challenges or lawsuits;

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negative publicity about our business or the oil and gas industry in general;

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increased costs of doing business;

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reduction in demand for our products; and

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other adverse effects on our ability to develop our properties and expand production.

We may need to incur significant costs associated with responding to these initiatives, and there is no guarantee that our responses will have the intended results. Complying with any resulting additional legal or regulatory requirements that are substantial could have a material adverse effect on our business, financial condition, cash flows, results of operations and ability to pay distributions on our common units.

Prolonged negative investor sentiment toward upstream natural gas and oil focused companies could limit our access to capital funding, which would constrain liquidity.

Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other sectors have led to lower natural gas and oil representation in certain key equity market indices. Some investors, including certain pension funds, private equity funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the natural gas and oil sector based on social and environmental considerations. Certain other stakeholders have pressured commercial and investment banks to directly funding or raising capital for hydrocarbon extraction, transportation or refining. If this negative sentiment continues or worsens, it may reduce the availability of capital funding for potential development projects, each of which could have a material adverse effect our financial condition, results of operations, cash flows and ability to pay distributions on our common units.

Conservation measures and technological advances could reduce demand for oil, natural gas and NGLs.

Fuel conservation measures, alternative fuel requirements, increasing availability of, and consumer and industrial/commercial demand for, alternatives to oil, natural gas and NGLs (e.g., alternative energy sources) and products manufactured with, or powered by, non-oil and gas sources (e.g., electric vehicles and renewable residential and commercial power supplies), and technological advances in fuel economy and energy generation, transmission, storage and consumption of energy (e.g., wind, solar and hydrogen power, smart grid technology and battery technology) could reduce demand for oil, natural gas and NGLs. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, our business could be impacted by governmental initiatives to incentivize the conservation of energy or the use of alternative energy sources. For example, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO₂ GHG emissions, such as methane and nitrous oxide. Further, the U.S. Department of Transportation recently issued more stringent fuel economy standards. These initiatives or similar state or federal initiatives to reduce energy consumption or incentivize a shift away from fossil fuels could reduce demand for hydrocarbons and have a material adverse effect on our earnings, cash flows and financial condition.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of unconventional natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas from dense subsurface rock formations. Hydraulic fracturing involves the injection of water,

sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Nearly all of our wells are drilled conventionally; however, from time to time, a small percentage of our wells are horizontally completed.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, more recently, in June 2016 governing CAA performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting and separately published in June 2016 an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. In addition, the BLM finalized rules in March 2015 establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands, including well casing and wastewater storage requirements and an obligation for exploration and production operators to disclose what chemicals they are using in fracturing activities. In December 2017, BLM issued a final rule repealing the 2015 hydraulic fracturing rule. The BLM’s rescission of the rule was challenged by several environmental groups and states in the United States District Court for the Northern District of California. The United States District Court for the Northern District of California upheld the BLM’s recission in a March 2020 decision. Additionally, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, states have continued to regulate hydraulic fracturing.

In the event that new federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we may incur additional costs to comply with such requirements when horizontally completing wells, which may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities, which could in turn have a material adverse effect on our business and results of operations.

See “Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of the laws and regulations that affect us.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us to incur costs or take other measures which may materially impact our business or operations.

The third parties on whom we rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, tribal and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. Please read “Business and Properties—Environmental Matters and Regulation” and “Business and Properties—Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

Derivatives regulation could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over the counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC has adopted rules that place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. These limitations could increase the costs to us of entering into, or lessen the availability of, derivative contracts to hedge or mitigate our exposure to volatility in oil, gas and NGL prices and other commercial risks affecting our business. The Dodd-Frank Act and CFTC rules will also require us, in connection with certain derivatives activities, to comply with clearing and trade execution requirements (or to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end user exception to the mandatory clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other

non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and natural gas companies, we are, from time to time, involved in various legal and other proceedings in the ordinary course of our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil, natural gas and NGLs, including the possibility of:

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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

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abnormally pressured formations;

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well blowouts;

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapses;

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fires, explosions and ruptures of pipelines;

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personal injuries and death;

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natural disasters; and

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terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

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injury or loss of life;

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damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations; and

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repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered or fully covered by insurance and any delay in the payment of insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.

Limitation or restrictions on our ability to obtain water may have an adverse effect on our operating results.

Water is an essential component of shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. In addition, the use, treatment and disposal of water has become a focus of certain investors and other stakeholders who may seek to engage with us on this and other environmental matters, which may result in activism, negative reputational impacts, increased costs or other adverse effects on our business, results of operations and financial condition. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition.

Risks Inherent in an Investment in Us

Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, Bob R. Simpson, our Chief Executive Officer and Chairman, Brent W. Clum, our President of Business Operations, Chief Financial Officer and Director, Keith A. Hutton, our President of Production and Development and Director, and Vaughn O. Vennerberg II, our former President, (collectively, the “Founders”) will own all of the membership interests in the sole member of our general partner. The Founders will also own an aggregate of approximately 27% of our outstanding common units. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the executive officers and directors of our general partner also have a duty, in certain cases, to manage our general partner at the direction of MSOG, which is owned by the Founders. As a result of these relationships, conflicts of interest may arise in the future between the Founders and their

respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our common unitholders. These conflicts include, among others, the following:

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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

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Neither our partnership agreement nor any other agreement requires the Founders or their respective affiliates (other than our general partner) to pursue a business strategy that favors us;

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The Founders and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us;

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Our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

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Our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

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Our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

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Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Duties.”

Our partnership agreement does not restrict our Founders and their respective affiliates from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities

that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit our Founders’ or their respective affiliates’ ability to compete with us and our Founders do not have any obligation to present business opportunities to us.

In addition, certain of our officers and directors may in the future hold similar positions with investment partnerships or other private entities that are in the business of identifying and acquiring mineral and royalty interests. In such capacities, these individuals would likely devote significant time to such other businesses and would be compensated by such other businesses for the services rendered to them. The positions of these directors and officers may give rise to duties that are in conflict with duties owed to us. In addition, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these potential future affiliations, they may have duties to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. Our Founders and their respective affiliates will be under no obligation to make any acquisition opportunities available to us. See “Conflicts of Interest and Duties.”

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, our Founders and their respective affiliates. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and holders of our common units.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production and make acquisitions.

Our partnership agreement provides that we distribute each quarter all of our available cash, which we define as cash on hand at the end of the each quarter, less reserves established by our general partner. As a result, we expect to rely primarily upon our cash reserves and external financing sources, including the issuance of additional common units and other partnership securities and borrowings under our Credit Facility, to fund future acquisitions and finance our growth. To the extent we are unable to finance growth with our cash reserves and external sources of capital, the requirement in our partnership agreement to distribute all of our available cash may impair our ability to grow.

A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

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general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

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conditions in the oil and gas industry;

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the market price of, and demand for, our common units;

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our results of operations and financial condition; and

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prices for oil, natural gas and NGLs.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our Credit Facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with different contractual standards. For example, our partnership agreement provides that:

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whenever our general partner (acting in its capacity as our general partner), the Board or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was not adverse to our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or equitable principle;

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our general partner may make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners at the time our partnership agreement was entered into where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

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how to allocate corporate opportunities among us and its other affiliates;

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whether to exercise its limited call right;

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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board;

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how to exercise its voting rights with respect to the units it owns;

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whether to sell or otherwise dispose of any units or other partnership interests it owns; and

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whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

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our general partner will not have any liability to us or our unitholders for breach of any duty in connection with decisions made in its capacity as general partner so long as it acted in good faith (meaning that it subjectively believed that the decision was not adverse to our best interest);

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our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

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approved by the conflicts committee of the Board, although our general partner is not obligated to seek such approval;

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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

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determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

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determined by the Board to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. In addition, as with other yield-oriented securities, our

unit price is impacted by the level of our cash distributions to our unitholders and implied distribution yield. This implied distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt. See “—Increased costs of capital could adversely affect our business.”

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain non-citizen unitholders.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption. Please read “The Partnership Agreement—Non-Citizen Unitholders; Redemption.”

Our unitholders have limited voting rights and are not entitled to elect our general partner or the Board, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The Board, including the independent directors, is chosen entirely by the Founders, as a result of their ownership of our general partner, and not by our unitholders. Please read “Management—Management of TXO Energy Partners” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner will have control over all decisions related to our operations. Since, upon consummation of this offering, affiliates of our general partner (including the Founders) collectively will own and control the voting of an aggregate of approximately 38% of our outstanding common units (excluding any common units purchased by our directors and executive officers and certain individuals identified by us under our directed unit program), the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. However, our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by the affiliates of our general partner (including the Founders)). Assuming we do not issue any additional common units and the affiliates of our general partner (including the Founders) do not transfer any of their common units, the affiliates of our general partner (including the Founders) will generally have the ability to significantly influence any amendment to our partnership agreement, including our policy to distribute all of our cash available for distribution to our unitholders. Furthermore, the goals and objectives of the affiliates of our general partner (including the Founders) that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “—Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.”

Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.

The public unitholders will be unable initially to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon completion of this offering to be able to prevent the removal of our general partner. The vote of the holders of at least 66 ²⁄₃% of all outstanding units voting together as a single class is required to remove our general partner. Following consummation of this offering, affiliates of our general partner (including the Founders) will own approximately 38% of our outstanding voting units (excluding any common units purchased by our directors and executive officers and certain individuals identified by us under our directed unit program), which will enable those holders, collectively, to prevent the removal of our general partner.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the Founders, who own MSOG, which wholly owns our general partner, from transferring all or a portion of their ownership interests in MSOG (or from causing MSOG to transfer all or a portion of its ownership interest in our general partner) to a third party. The new owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and thereby influence the decisions made by the Board and officers.

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval.

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

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our unitholders’ proportionate ownership interest in us will decrease;

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the amount of cash available for distribution on each unit may decrease;

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the ratio of taxable income to distributions may increase;

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the relative voting strength of each previously outstanding unit may be diminished; and

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the market price of our common units may decline.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group owning 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the Board, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

Once our common units are publicly traded, the Existing Owners may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby the Founders will own 8,028,129 common units, or approximately 27% of our limited partner interest, and, the Existing Owners (including the Founders) will own 25,000,000 common units, or approximately 83% of our limited partner interests. Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates, which includes the Founders. Once our common units are publicly traded, the sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the then outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercises its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. At the closing of this offering, affiliates of our general partner will own approximately 38% of our common units (excluding any common units purchased by our directors and executive officers and certain individuals identified by us under our directed unit program). For additional information about this call right, please read “The Partnership Agreement—Limited Call Right.”

Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner or its directors, officers or other employees.

Our partnership agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court in the State of Delaware with subject matter jurisdiction) will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. The foregoing provision will not apply to any claims as to which the Court of Chancery determines that there is an indispensable party not subject to the jurisdiction of such court, which is rested in the exclusive jurisdiction of a court or forum other than such court (including claims arising under the Exchange Act), or for which such court

does not have subject matter jurisdiction, or to any claims arising under the Securities Act and, unless we consent in writing to the selection of an alternative forum, the United States federal district courts will be the sole and exclusive forum for resolving any action asserting a claim arising under the Securities Act. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules or regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain such Securities Act claims. To prevent having to litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, the partnership agreement provides that, unless we consent in writing to the selection of an alternative forum, United States federal district courts shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. There is uncertainty as to whether a court would enforce the forum provision with respect to claims under the federal securities laws. If a court were to find these provisions of our amended and restated agreement of limited partnership inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Our partnership agreement also provides that each limited partner waives the right to trial by jury in any such claim, suit, action or proceeding, including any claim under the U.S. federal securities laws, to the fullest extent permitted by applicable law. If a lawsuit is brought against us under our partnership agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may result in different outcomes than a trial by jury would have, including results that could be less favorable to the plaintiffs in any such action. No unitholder can waive compliance with respect to the U.S. federal securities laws and the rules and regulations promulgated thereunder. If the partnership or one of the partnership unitholders opposed a jury trial demand based on the waiver, the applicable court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with applicable state and federal laws. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the U.S. federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual pre-dispute jury trial waiver provision is generally enforceable, including under the laws of the State of Delaware, which govern our partnership agreement. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations, provisions and obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us, our general partner and our general partner’s directors and officers. For additional information about the exclusive forum provision of our partnership agreement, please read “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.”

The NYSE does not require a publicly traded partnership like us to comply, and we do not intend to comply, with certain of its governance requirements generally applicable to corporations.

We have been approved to list our common units on the NYSE under the symbol “TXO.” Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Management—Management of TXO Energy Partners”

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a Delaware limited partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:

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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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a unitholder’s right to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

Please read “The Partnership Agreement—Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

Our unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Our unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and our unitholders may not be able to resell their common units at the initial public offering price.

Prior to this offering, there has been no public market for the common units. After this offering, there will be 5,000,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

If our common unit price declines after the initial public offering, our unitholders could lose a significant part of their investment.

The initial public offering price for the common units was determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common

units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

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changes in commodity prices;

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changes in securities analysts’ recommendations and their estimates of our financial performance;

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public reaction to our press releases, announcements and filings with the SEC;

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fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

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changes in market valuations of similar companies;

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departures of key personnel;

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commencement of or involvement in litigation;

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variations in our quarterly results of operations or those of other oil and natural gas companies;

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variations in the amount of our quarterly cash distributions to our unitholders;

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changes in tax law;

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an election by our general partner to convert or restructure us as a taxable entity;

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future issuances and sales of our common units; and

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changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation.

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board (“PCAOB”) requiring mandatory audit firm rotation or a supplement to the

auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our common units less attractive to investors.

We intend to take advantage of all of the reduced reporting requirements and exemptions available to emerging growth companies under the JOBS Act, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. We cannot predict if investors will find our common units less attractive because we will rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our common unit price may be more volatile. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

Our general partner may elect to convert or restructure us from a partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent.

Under our partnership agreement, our general partner may, without unitholder approval, cause us to be treated as an entity taxable as a corporation or subject to entity-level taxation for U.S. federal income tax purposes, whether by election of the partnership or conversion of the partnership or by any other means or methods. In addition and as part of such determination, affiliates of our general partner may choose to retain their partnership interests in us and cause us to enter into a transaction in which our interests held by other persons are converted into or exchanged for interests in a new

entity, taxable as a corporation or subject to entity-level taxation for U.S. federal purposes, whose sole assets are interests in us. The general partner may take any of the foregoing actions if it in good faith determines (meaning it subjectively believes) that such action is not adverse to our best interests. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. The tax liability, if any, of a unitholder as a result of such an event may be material to such unitholder and may vary depending on the unitholder’s particular situation and may vary from the tax liability of us or of any affiliates of our general partner who choose to retain their partnership interests in us. Our general partner will have no duty or obligation to make any such determination or take any such actions, however, and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in a manner not adverse to the best interests of us or our limited partners. Please read “The Partnership Agreement—Election to be Treated as a Corporation.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting.

We also expect to incur additional expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the Board or as executive officers than it was prior to this offering.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our units or if our operating results do not meet their expectations, our unit price could decline.

The trading market for our common units will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our unit price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common units or if our operating results do not meet their expectations, our unit price could decline.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, prospective unitholders should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (the “IRS”) were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution to our unitholders could be reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our classification as a partnership for federal income tax purposes.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders could be reduced. Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in New Mexico, Texas and Colorado, among other states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships.

Any changes to federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. Any such changes or interpretations thereof could adversely impact the value of an investment in our common units.

Certain U.S. federal income tax incentives currently available with respect to oil and natural gas exploration and production may be reduced or eliminated as a result of future legislation.

In recent years, legislation has been proposed that would, if enacted, make significant changes to United States tax laws, including the reduction or elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units. Please Read “Material U.S. Federal Income Tax Consequences—Recent Legislative Developments.”

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

We will generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders because the costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we would pay the taxes directly to the IRS. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable

penalties and interest) resulting from such audit adjustment directly from us. Our general partner would cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount from the cash that we distribute, our unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.

Tax gains or losses on the disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation, depletion, amortization and IDCs. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss.”

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business (“business interest”) may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our common units.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”) or other retirement plans, and non-U.S. persons raise issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable

income and will be taxable to them. A tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor regarding the impact of these rules on an investment in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and other Investors.”

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to non-U.S. unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of our common units occurring before January 1, 2023. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and other Investors.”

We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in New Mexico, Texas and Colorado, among other states. New Mexico and Colorado each impose a personal income tax. Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. It is the responsibility of each unitholder to file its own federal, state and local tax returns, as applicable.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.

We will adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

USE OF PROCEEDS

We intend to use the expected net proceeds of approximately $88.0 million from this offering, based upon the initial public offering price of $20.00 per common unit, after deducting underwriting discounts and estimated expenses, to repay a portion of the amounts outstanding under our revolving credit facility (our “Credit Facility”).

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds would be approximately $14.0 million. The net proceeds from any exercise of such option will be used for general partnership purposes. Please read “Underwriting.”

As of December 31, 2022, we had $113 million of outstanding borrowings under our Credit Facility, which has a maturity date of November 1, 2025. Borrowings outstanding under our Credit Facility bore interest at a weighted average rate of 6.4% per annum as of September 30, 2022. The outstanding borrowings under our Credit Facility were incurred to partially fund the acquisition of the Vacuum Properties.

The sources and use of our proceeds may differ from those set forth above. The foregoing represents our current intentions with respect to the use and allocation of the net proceeds of this offering based upon our present plans and business condition, but our management will have significant flexibility and discretion in applying the net proceeds. The occurrence of unforeseen events or changed business conditions could result in application of the net proceeds of this offering in a manner other than as described in this prospectus.

CAPITALIZATION

The following table shows:

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historical capitalization as of September 30, 2022; and

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our capitalization as of September 30, 2022 as adjusted to give effect to (i) the Reorganization Transactions (including the Reverse Unit Split) and (ii) this offering and the application of the net proceeds from this offering as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, please read our Unaudited Pro Forma Condensed Financial Statements.


	As of September 30, 2022 (Historical)		As of September 30, 2022 (As Adjusted)
	(In thousands)

Cash and cash equivalents	$	11,148	$	11,148


Long-term debt(1)	$	132,100	$	44,100

Members’/partners’ capital/net equity:

Common equity held by public		—	$	88,000

Common equity held by the Existing Owners	$	309,123	$	549,492

Series 3 Preferred Equity(2)(3)	$	34,295		—

Series 5 Preferred Equity(4)	$	206,074		—


Total members’/partners’ capital/net equity	$	549,492	$	637,492


Total capitalization	$	681,592	$	681,592

(1)	As of December 31, 2022, we had $113.0 million in outstanding borrowings under our Credit Facility.

(2)	The Series 3 Preferred Units automatically converted into 270,831 common units on October 1, 2022.

(3)	Effective as of October 1, 2022, all of MorningStar Partners, L.P.’s outstanding Series 3 warrants were exercised for 81,249 common units.

(4)	The Series 5 Preferred Units will be exchanged into 10,235,081 common units in connection with the Reorganization Transactions.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after this offering. Net tangible book value is our total tangible assets less total liabilities. On a pro forma basis as of September 30, 2022, after giving effect to this offering of common units, the Reorganization Transactions (including the Reverse Unit Split) and the application of the related net proceeds, our net tangible book value would have been $637.5 million, or $21.25 per unit. Purchasers of common units in this offering will experience substantial and immediate accretion in net tangible book value per common unit for accounting purposes, as illustrated in the following table:



Initial public offering price per common unit				$	20.00

Pro forma net tangible book value per unit before this offering⁽¹⁾	$	21.98

Decrease in net tangible book value per unit attributable to purchasers in the offering		(0.73	)


Less: Pro forma net tangible book value per unit after this offering⁽²⁾					21.25


Immediate accretion in net tangible net book value per common unit to purchasers in the offering⁽³⁾				$	1.25

(1)	Determined by dividing the pro forma net tangible book value of our net assets immediately prior to the offering by the number of common units held by the Existing Owners, after giving effect to the Reorganization Transactions, including the Reverse Unit Split.

(2)

Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the net proceeds of this offering, by the total number of units to be outstanding after this offering after giving effect to the Reorganization Transactions, including the Reverse Unit Split.

(3)

Because the total number of units outstanding following the consummation of this offering will be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will be retained by us, there will be a change to the accretion in net tangible book value per common unit to purchasers in the offering due to any such exercise of the underwriters’ option to purchase additional common units.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by the Existing Owners and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus after giving effect to the Reorganization Transactions, including the Reverse Unit Split:


	Units Acquired					Total Consideration
	Number		Percent			Amount		Percent
						(in thousands)

Existing Owners		25,000,000		83	%	$	500,000,000		85	%

Purchasers in the offering⁽¹⁾		5,000,000		17	%	$	88,000,000		15	%


Total		30,000,000		100.0	%	$	588,000,000		100.0	%

(1)	Total consideration is after deducting underwriting discounts and estimated offering expenses.

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

General

Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash each quarter. Our cash distribution policy reflects a basic judgment that our unitholders generally will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions from our available cash in the aforementioned or any other amount, and our general partner has considerable discretion to determine the amount of cash available for distribution each quarter. Generally, we define available cash as the sum of our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves, (ii) cash on hand on the date on which our general partner determines the amount of cash available for distribution, which we refer to as the date of determination, resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter, and (iii) if our general partner so determines, cash on hand at the date of determination resulting from working capital borrowings made after the end of the quarter. We may, but are under no obligation to, borrow funds to make quarterly distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Further, we may rely upon our cash reserves (including the net proceeds that we will retain from this offering) and external financing sources, including borrowings under our Credit Facility (under which no amounts will be outstanding at the closing of this offering) and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. We also plan to continue our practice of opportunistically entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations, and therefore reduce volatility in quarterly distributions. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to such federal income tax.

Because our policy will be to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low revenue, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. Our quarterly cash distributions from our available cash, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in the performance of our operators and revenue caused by fluctuations in the prices of oil and natural gas. Such variations may be significant.

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

less, the amount of cash reserves established by our general partner to:

•

provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to our unitholders for any one or more of the next four quarters;

plus, all cash on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter;

plus, if our general partner so determines, all or a portion of cash on hand on the date of determination resulting from working capital borrowings made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions from our available cash to our unitholders at the level currently estimated or at all, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

•

Our cash distribution policy may be subject to restrictions on distributions under our Credit Facility or other debt agreements that we may enter into in the future. Specifically, our Credit Facility contains financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement.” Should we be unable to satisfy these restrictions, or if a default occurs under our Credit Facility, we would be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.

•

The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders. If our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain the current production levels over the long-term of our oil and natural gas properties, we will be unable to pay any cash distributions from cash generated from operations. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may have the effect of, and may effectively represent, a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment.

•

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders.

•

Although our partnership agreement requires us to distribute all of our available cash each quarter, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by affiliates of our general partner). At the closing of this offering, the affiliates of our general partner (including the Founders) will own approximately 38% of our outstanding common units. For more information, please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

•

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

•

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including decreases in commodity prices, decreases in our oil and natural gas production, or increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements or anticipated cash needs.

•

We own a 50% interest in Cross Timbers, with the other 50% owned by the XTO entities. Pursuant to the JV LLCA, Cross Timbers is managed by us and governed by a member management committee comprised of six members, three of whom are appointed by us and three of whom are appointed by the XTO Entities. Cross Timbers is required to distribute all net cash flow to the members of Cross Timbers pro rata in accordance with their respective membership interests on a quarterly basis pursuant to the JV LLCA, with such net cash flow being calculated net of reserves for reasonable and prudent operations as determined by the majority of the management committee. Therefore, we do not have sole control of the amount of distributions to be made by Cross Timbers.

•

If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund maintenance or growth capital expenditures.

•

We will not have a minimum quarterly distribution. Furthermore, none of our limited partner interests, including those held by the Founders or Existing Owners, will be subordinate in right of payment to the common units sold in this offering.

•

Our general partner may reduce our distributions if action is taken by our general partner as described under “Our Partnership Agreement—Election to be treated as a Corporation” that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for federal income tax purposes. In such an event, the distribution levels may be reduced to account for any current and future estimated tax liabilities we would incur as a corporation. The distributions will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Our Partnership Agreement Requires That We Distribute All of Our Available Cash, Which Could Limit Our Ability to Grow

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, our growth may not be as fast as the growth of businesses that reinvest all of their available cash to expand ongoing operations. Further, we may rely upon our cash reserves (including the net proceeds that we will retain from this offering) and external financing sources, including borrowings under our Credit Facility (under which no amounts will be outstanding at the closing of this offering) and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. Our management has collectively invested more than $500 million in us since our inception. Following the completion of this offering, we expect that we will not be able to rely on our management or our partners for capital and will need to utilize the public equity or debt markets and bank financings to fund acquisitions and capital expenditures. To the extent we require external sources of capital to fund our growth and are unable to access such sources, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy may impair our ability to grow. Our Credit Facility limits, and any future debt agreements may limit, our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Our Credit Facility has restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.” To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors —Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Increases in interest rate could adversely impact our unit price and our ability to issue additional equity and incur debt.”

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2021 and the Twelve Months Ended September 30, 2022

On a pro forma basis, assuming we had completed this offering on January 1, 2021, our cash available for distribution for the year ended December 31, 2021 and the twelve months ended September 30, 2022 would have been approximately $89.6 million and $133.0 million, respectively. This amount would have been sufficient to pay a cash distribution of $0.75 per unit per quarter ($2.99 on an annualized basis) during the year ended December 31, 2021, and a cash distribution of $1.11 per unit per quarter ($4.43 on an annualized basis) during the twelve-month period ended September 30, 2022.

The unaudited pro forma financial data does not give pro forma effect to the incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership. We estimate that these incremental general and administrative

expenses initially will be approximately $3.0 million per year. Such incremental general and administrative expenses are not reflected in our historical or pro forma financial statements. Our unaudited pro forma cash available for distribution does not include the Andrews Parker acquisition for the period prior to the acquisition or the Additional Interest Vacuum Acquisition in August 2022, and only gives effect to the Andrews Parker acquisition for results from and after the date of acquisition, December 30, 2021.

The pro forma financial statements, from which pro forma cash available for distribution is derived, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

The following table illustrates, on an unaudited pro forma basis for the year ended December 31, 2021 and the twelve months ended September 30, 2022, the amount of available cash that would have been available for distribution to our unitholders, assuming in each case that this offering had been consummated on January 1, 2021.

TXO Energy Partners, L.P.

Unaudited Pro Forma Cash Available for Distribution


	Pro Forma
	Year Ended December 31, 2021			Twelve Months Ended September 30, 2022
	(in thousands, except per unit data)

Net Income(1)	$	64,658		$	40,143

Interest Expense, Net		3,907			5,361

DD&A		47,650			42,567

Impairment Expenses		—			—

Accretion of Discount on Asset Retirement		4,962			5,695

Exploration Expense		124			323

Non-Cash Derivative (Gain)/Loss		(8,977	)		54,439

Other Non-Cash (Gain)/Loss		(8,687	)		(556	)


Adjusted EBITDAX(2)	$	103,637		$	147,972

Development Costs		(8,372	)		(8,591	)

Cash Interest Expense, Net		(2,555	)		(4,059	)

Exploration Expense		(124	)		(323	)

Public Company Expense		(3,000	)		(3,000	)

Non-Recurring (Gain)/Loss		—			1,029


Cash Available for Distribution(3)	$	89,586		$	133,028


Pro Forma Annualized distributions per unit	$	2.99		$	4.43


	Pro Forma
	Year Ended December 31, 2021		Twelve Months Ended September 30, 2022
	(in thousands, except per unit data)

Pro Forma Estimated annual cash distributions:

Distributions on common units held by purchasers in this offering	$	14,931	$	22,171

Distributions on common units held by our Existing Owners		74,655		110,857


Total estimated annual cash distributions	$	89,586	$	133,028

(1)	Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)	Adjusted EBITDAX is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

(3)	Cash available for distribution is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2023

The financial forecast presents, to the best of our knowledge and belief, our expected results of operations, Adjusted EBITDAX and cash available for distribution for the twelve months ending September 30, 2023. Based upon the assumptions and considerations set forth in the table below, we estimate that we will generate $112.4 million in cash available for distribution for the twelve months ending September 30, 2023, which would be sufficient to pay cash distributions of $3.75 per common unit. The number of outstanding common units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering, including the expected award of 545,000 phantom units to certain executives and key employees. Furthermore, the financial forecast assumes that we do not make any acquisitions of properties during the twelve months ending September 30, 2023.

Our Statement of Estimated Adjusted EBITDAX reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take in order to be able to be able to generate cash available for distribution in the amount of $3.75 per common unit, or $112.4 million in the aggregate for the twelve months ending September 30, 2023. The assumptions discussed below under “—Assumptions and Considerations” are those that we believe are significant to our ability to generate the requisite Adjusted EBITDAX. Based on such assumptions, we believe our actual results of operations and cash flow will be sufficient to generate the Adjusted EBITDAX necessary to pay the forecasted aggregate annualized cash distribution. We can, however, give you no assurance that we will generate this amount. There will likely be differences between our estimated Adjusted EBITDAX and our actual results, and those differences could be material. If we fail to generate the estimated Adjusted EBITDAX contained in our forecast, our annualized cash distribution to all of our unitholders may be less than expected. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions from our available cash on our common units.

While we do not, as a matter of course, make public projections as to future sales, earnings or other results, our management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDAX below to substantiate our belief that we will have sufficient cash to pay the forecasted cash distribution on all of our common units for twelve months ending September 30, 2023. This forecast is a forward-looking statement and should be read together with our historical financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of

Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate Adjusted EBITDAX necessary for us to pay cash distribution on all of our outstanding common for the twelve months ending September 30, 2023 equal to $3.75 per common unit. Readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “—Assumptions and Considerations,” including the sensitivity analysis included therein.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. KPMG LLP has not compiled, examined or performed any procedures with respect to the accompanying prospective financial information and, accordingly, KPMG LLP does not express any opinion or any other form of assurance with respect thereto. The KPMG LLP reports included in the registration statement relate to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the Adjusted EBITDAX necessary to pay the forecasted aggregate annualized cash distribution on all of our outstanding common units for the twelve months ending September 30, 2023.

We are providing the Statement of Estimated Adjusted EBITDAX to supplement our historical financial statements and in support of our belief that we will have sufficient available cash to pay the forecasted aggregate annualized cash distribution on all of our outstanding common units for the twelve months ending September 30, 2023. Please read below under “—Assumptions and Considerations” for further information about the assumptions we have made for the financial forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

Our Estimated Cash Available for Distribution

The following table shows how we calculate estimated available cash for the twelve months ending September 30, 2023 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending September 30, 2023 in the table below are estimates. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”

Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.


	Three Months Ending December 31, 2022			Three Months Ending March 31, 2023			Three Months Ending June 30, 2023			Three Months Ending September 30, 2023			Twelve Months Ending September 30, 2023
	(in thousands, except per unit data) (unaudited)

Estimated Net Income(1)	$	22,388		$	32,101		$	22,600		$	24,750		$	101,839

Interest Expense, Net		1,079			461			425			431			2,396

DD&A		12,383			12,320			12,377			12,521			49,601

Impairment Expenses		—			—			—			—			—

Accretion of Discount on Asset Retirement		1,596			1,596			1,596			1,596			6,384

Exploration Expense		48			48			48			48			192

Non-Cash Derivative (Gain)/Loss(2)		—			—			—			—			—

Other Non-Cash (Gain)/Loss(3)		—			—			—			—			—

Estimated Adjusted EBITDAX(4)	$	37,494		$	46,526		$	37,046		$	39,346		$	160,412

Development Costs		(21,511	)		(2,998	)		(8,295	)		(13,279	)		(46,083	)

Cash Interest Expense, Net		(906	)		(289	)		(253	)		(259	)		(1,707	)

Exploration Expense		(48	)		(48	)		(48	)		(48	)		(192	)

Non-Recurring (Gain)/Loss(3)		—			—			—			—			—


Estimated Cash Available for Distribution(5)	$	15,029		$	43,191		$	28,450		$	25,760		$	112,430


Estimated Cash distribution per unit	$	0.50		$	1.44		$	0.95		$	0.86		$	3.75


Estimated cash distributions(6):

Distributions on common units held by purchasers in this offering (5,000,000)	$	2,505		$	7,198		$	4,742		$	4,293		$	18,738

Distributions on common units held by the Existing Owners (25,000,000)	$	12,524		$	35,993		$	23,708		$	21,467		$	93,692


Total estimated annual cash distributions	$	15,029		$	43,191		$	28,450		$	25,760		$	112,430

(1)	Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)

Does not include an estimate of unrealized derivative (gain)/loss because the forecast period assumes the commodity prices set forth below under “—Assumptions and Considerations-Operations and Revenue—Prices” remain constant during the period. For additional information regarding the impact of changes in commodity prices, please see “—Sensitivity Analysis” below.

(3)	Does not include estimated Non-Cash (Gain) / Loss or Non-Recurring (Gain) / Loss, which cannot be accurately forecasted for future periods.

(4)	Adjusted EBITDAX is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

(5)	Cash available for distribution is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

(6)

The number of outstanding common units assumed herein does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering, including the expected award of 545,000 phantom units to certain executives and key employees.

Assumptions and Considerations

Based upon the specific assumptions outlined below, we expect to generate cash available for distribution for the twelve months ending September 30, 2023 of approximately $112.4 million.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the forecasted estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Production. Our ability to generate sufficient cash from operations to pay cash distributions to unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. Production volumes directly impact our revenue. Any negative effect on production volumes could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution. Our existing production will naturally decline over time as the applicable reservoir is depleted. Our decline rate for our oil and gas properties over the next twelve months in the Permian and San Juan basins, is currently estimated to be approximately 7% and 10%, respectively.

The following table presents historical production volumes for our properties on a pro forma basis for the Vacuum Properties for the year ended December 31, 2021 and the twelve months ended September 30, 2022 and on a forecasted basis for the twelve months ending September 30, 2023:


	Pro Forma Year Ended December 31, 2021		Pro Forma Twelve Months Ended September 30, 2022		Forecasted Twelve Months Ending September 30, 2023

Annual production:

Oil and condensate (MBbl)		1,779		2,040		2,485

Natural gas liquids (MBbl)		1,137		1,286		1,352

Natural gas (MMcf)		30,674		30,678		31,319


Total (MBoe)		8,029		8,439		9,057


Average net daily production:

Oil and condensate (MBbl/d)		4.9		5.6		6.8

Natural gas liquids (MBbl/d)		3.1		3.5		3.7

Natural gas (MMcf/d)		84.0		84.0		85.8


Total (MBoe per day)		22.0		23.1		24.8

We estimate that our total oil and natural gas production for the twelve months ending September 30, 2023 will be 24.8 MBoe per day as compared to 22.0 MBoe per day on a pro forma basis for the year ended December 31, 2021 and 23.1 MBoe per day on a pro forma basis for the twelve months ended September 30, 2022. For the month ended September 30, 2022, our average net production was approximately 23.8 MBoe per day. We intend to maintain our forecasted production

level of 24.8 MBoe per day for the twelve months ending September 30, 2023 with cash generated from operations. These estimates include production from the Andrews Parker Acquisition and the Additional Interest Vacuum Acquisition.

Prices. Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile and currently are at record or near record-high levels. During the period from January 1, 2021 through December 31, 2022, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $23.86 per MMBtu, respectively, and a low of $47.62 per Bbl and $2.43 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which is redetermined semi-annually.

The NYMEX WTI, for oil prices, and NYMEX Henry Hub, for gas prices, are widely used benchmarks for the pricing of oil and natural gas in the United States. The price we receive for our oil and natural gas production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. The differentials to published oil and natural gas prices are based upon our analysis of the historic price differentials for production from the mineral interests with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur. The table below illustrates the relationship between average oil, natural gas and natural gas liquids realized sales prices and average NYMEX futures prices as of September 30, 2022 on a pro forma basis for the year ended December 31, 2021 and the twelve months ended September 30, 2022 and our forecast for the twelve months ending September 30, 2023:


	Pro Forma Year Ended December 31, 2021			Pro Forma Twelve Months Ended September 30, 2022			Forecasted Twelve Months Ending September 30, 2023

Average oil sales prices (Bbl):

Average daily NYMEX-WTI oil price	$	67.92		$	92.86		$	80.99

Differential to NYMEX-WTI oil	$	(1.69	)	$	0.44		$	(0.93	)

Realized oil sales price (excluding derivatives)	$	66.23		$	93.30		$	80.06

Realized oil sales price (including derivatives)	$	66.23		$	79.22		$	74.95

Average natural gas liquids sales prices (Bbl):

Average daily NYMEX-WTI oil price	$	67.92		$	92.86		$	80.99

Differential to NYMEX-WTI oil price		38.0	%		39.4	%		37.1	%

Realized natural gas liquids sales price (excluding derivatives)	$	25.79		$	36.61		$	30.07

Realized natural gas liquids sales price (including derivatives)	$	25.79		$	32.75		$	29.22

Average natural gas sales prices (Mcf):

Average daily NYMEX-Henry Hub natural gas price	$	3.84		$	6.54		$	5.50

Differential to NYMEX-Henry Hub natural gas		0.15		$	(0.55	)	$	(0.38	)

Realized natural gas sales price (excluding derivatives)	$	3.99		$	5.99		$	5.12

Realized natural gas sales price (including derivatives)	$	3.99		$	4.80		$	4.30

Hedging Activities. We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. We were required under our Credit Facility to hedge at least 75% of reasonably anticipated projected production of proved developed producing reserves for the 12-month period following January 1, 2022. However, as of any time, if the net leverage ratio (the ratio of total net debt-to-EBITDAX) is less than or equal to 1.0 to 1.0 and the cash and cash equivalents on hand are equal to or greater than 20% of the borrowing base then in effect, the minimum required hedge volume for month one through month 24 will be reduced to 50%. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. However, from September 30, 2022 through the next scheduled redetermination in March 2023, we received a waiver to reduce the hedging requirement from 30 months to 18 months beginning January 1, 2023 and from 50% to 45% of the reasonably anticipated projected production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement” for more information. Our policy is to consider hedging a portion of our production at commodity prices management deems attractive.

As of the date of this prospectus, our commodity derivative contracts will cover 1,005 MBbl, or approximately 40.4%, of our forecasted total oil production of 2,485 MBbl, 617 MBbl, or approximately 45.6%, of our forecasted total natural gas liquid production of 1,352 MBbl, and 15,525 Mcf, or approximately 49.6%, of our forecasted total natural gas production of 31,319 Mcf, for the twelve months ending September 30, 2023. Our commodity derivative contracts consist of swap and collar agreements based upon NYMEX-WTI prices. The table below shows the volumes and prices covered by the commodity derivative contracts for the twelve months ending September 30, 2023. For purposes of our forecast, we have assumed that we will not enter into additional natural gas or oil derivative contracts during the forecast period, although we may do so on an opportunistic basis if market conditions are favorable. See “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—We use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.”


	Swaps					Collars
	Volume per Day			Weighted Avg. Price		Volume per Day			Weighted Avg. Floor Price

Oil:

August 2022 - September 2023 (Bbl/d)		2,752		$	69.64		—			—

% of Forecasted Production		40.4	%		—		—			—

Natural Gas Liquids:

August 2022 - September 2023 (Gal/d)		70,940		$	0.36		—			—

% of Forecasted Production		45.6	%		—		—			—

Natural Gas:

August 2022 - September 2023 (MMBtu/d)		37,521		$	3.73		5,014		$	3.87

% of Forecasted Production		43.7	%		—		5.8	%		—

Operating Revenues and Realized Commodity Derivative Gains. The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2021 and the twelve months ended September 30, 2022 and on a forecasted basis for the twelve months ending September 30, 2023:


	Pro Forma Year Ended December 31, 2021		Pro Forma Twelve Months Ended September 30, 2022			Forecasted Twelve Months Ending September 30, 2023
(in thousands)

Oil:

Oil revenues (excluding the effects of derivative instruments)	$	118,186	$	190,376		$	198,977

Realized oil derivative instruments gain (loss)		—		(28,731	)		(12,705	)


Total	$	118,186	$	161,645		$	186,272


Natural gas liquids:

Natural gas liquids revenue (excluding the effects of derivative instruments)	$	29,810	$	47,059		$	40,649

Realized natural gas liquids derivative instruments gain (loss)		—		(4,964	)		(1,157	)


Total	$	29,810	$	42,095		$	39,492


Natural gas:

Natural gas revenues (excluding the effects of derivative instruments)	$	130,676	$	183,895		$	160,494

Realized natural gas derivative instruments gain (loss)		—		(36,548	)		(25,977	)


Total	$	130,676	$	147,347		$	134,517


Total:

Operating revenues	$	278,672	$	421,330		$	400,120

Commodity derivative instruments gain (loss)		—		(70,243	)		(39,839	)


Operating revenue and realized commodity derivative instruments gains	$	278,672	$	351,087		$	360,281

Expenses

Development Costs. Our estimated development costs for the twelve months ending September 30, 2023 of $46.1 million represent our estimate of the average annual capital expenditures necessary, together with the forecasted production from the Andrews Parker Acquisition and the Additional Interest Vacuum Acquisition, to achieve our forecasted production level of 24.8 MBoe per day for the twelve months ending September 30, 2023.

Production Expenses. The following table summarizes production expenses on an aggregate basis and on a per Boe basis for the year ended December 31, 2021, pro forma, the twelve months ended September 30, 2022, pro forma, and on a forecasted basis for the twelve months ending September 30, 2023:


	Pro Forma Year Ended December 31, 2021		Pro Forma Twelve Months Ended September 30, 2022		Forecasted Twelve Months Ended September 30, 2023

Production expenses (in thousands)	$	99,406	$	124,218	$	129,444

Production expenses (per Boe)	$	12.38	$	14.72	$	14.29

We estimate that our production expenses for the twelve months ending September 30, 2023 will be approximately $129.4 million. Production expenses consist of lease operating expenses incurred for the operation and maintenance of wells and related equipment. On a pro forma basis, for the year ended December 31, 2021 and the twelve months ended September 30, 2022, production expenses were $99.4 million and $124.2 million, respectively.

Taxes, transportation and other. Taxes, transportation, and other expenses consist primarily of gathering fees and processing fees, transportation costs, severance taxes, and ad valorem taxes. Gathering, processing and transportation costs are recognized when control of the natural gas we sell occurs at the tailgate of the processing plant. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by state or local taxing authorities. In general, the severance taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. We evaluate taxes, transportation, and other expense on a per Boe basis to monitor costs to ensure that they are at acceptable levels. Taxes, transportation, and other expenses can also be influenced by acquisitions, commodity prices, changes in values of our properties, sales mix and acquisitions.

The following table summarizes taxes, transportation and other on a pro forma basis for the year ended December 31, 2021, the twelve months ended September 30, 2022 and on a forecasted basis for the twelve months ending September 30, 2023:


	Pro Forma Year Ended December 31, 2021		Pro Forma Twelve Months Ended September 30, 2022		Forecasted Twelve Months Ended September 30, 2023

Taxes, transportation and other (in thousands)	$	63,103	$	93,389	$	92,948

Taxes, transportation and other (per Boe)	$	7.86	$	11.07	$	10.26

General and Administrative Expenses. General and administrative expenses consist primarily of personnel related costs and are partially offset by certain reimbursements of overhead expenses, including Texas gross margin taxes. In connection with the consummation of this offering, we expect to incur additional costs related to being a public company. For example, the SEC proposed rules on climate change disclosure requirements for public companies which, if adopted as proposed, could result in substantial compliance costs. However, we do not expect to experience a material change in our cash cost structure, except as may be affected by our recent property acquisitions, the volatility of commodity prices, increased expenses as a publicly traded limited partnership, the effectives of our commodity derivative contracts, and the effects of impairment on our producing properties. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Factors Affecting the Comparability of Our Financial Condition and Results of Operations.”

Interest Expense. Interest expense is primarily a result of interest on our borrowings on our Credit Facility to fund operations and acquisitions of properties as well as the amortization of debt issuance costs associated with these borrowings. Interest expense can fluctuate with our level of indebtedness as well as changes in interest rates and includes commitment fees under our Credit Facility.

Our Credit Facility requires us to maintain (i) a current ratio greater than 1.0 to 1.0 and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.00 to 1.00. For purposes of our current ratio covenant, “current assets” is deemed to include availability under the Credit Facility but excludes the unrealized gain (loss) of derivative instruments. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement” for additional detail regarding the covenants and restrictive provisions included in our Credit Facility.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending September 30, 2023 is based on the following significant assumptions related to regulatory, industry and economic factors:

•

There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or any interpretation of existing regulations, that will be materially adverse to our business;

•

There will not be any material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor;

•

All supplies and commodities necessary for production and sufficient transportation will be readily available;

•

There will not be any major adverse change in commodity prices or the energy industry in general;

•

There will not be any material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events, including any events that could lead to force majeure under any of our marketing agreements;

•

There will not be any adverse change in the markets in which we operate resulting from supply or production disruptions, reduced demand for our product or significant changes in the market prices for our product; and

•

Market, insurance, regulatory and overall economic conditions will not change substantially.

Sensitivity Analysis

Our ability to generate sufficient cash from operations to pay cash distributions to our unitholders is a function of two primary variables: (i) production volumes; and (ii) commodity prices. In the tables below, we illustrate the effect that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the forecasted cash distributions on our outstanding common units for the twelve months ending September 30, 2023.

We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impracticable to provide because of the number of assumptions and variables involved that have interdependent effects on the potential outcome.

Production Volume Changes

Production volumes directly impact our revenue. Any negative effect on production volumes could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution. The following table shows estimated Adjusted EBITDAX under production levels of 80%, 100% and 120% of the production level we have forecasted for the twelve months ending September 30, 2023. The estimated Adjusted EBITDAX amounts shown below are based on the assumptions used in our forecast.


	Percentage of Forecasted Net Production
	80%			100%			120%
	(in thousands, except per unit amounts)

Forecasted net production:

Oil (MBbl)		1,988			2,485			2,982

Natural gas (MMcf)		25,055			31,319			37,583

Natural gas liquids (MBbl)		1,081			1,352			1,622


Total (MBoe)		7,245			9,057			10,868

Oil (Bbl/d)		5,447			6,808			8,170

Natural gas (Mcf/d)		68,644			85,805			102,967

Natural gas liquids (Bbl/d)		2,962			3,704			4,444


Total (Boe per day)		19,849			24,814			29,775

Forecasted prices:

NYMEX-WTI oil price (per Bbl)	$	80.99		$	80.99		$	80.99

Realized oil price (per Bbl) (excluding derivatives)		80.06			80.06			80.06

Realized oil price (per Bbl) (including derivatives)		74.95			74.95			74.95

NYMEX-WTI natural gas liquids price (per Bbl)	$	80.99		$	80.99		$	80.99

Realized natural gas liquids price (per Bbl) (excluding derivatives)		30.07			30.07			30.07

Realized natural gas liquids price (per Bbl) (including derivatives)		29.22			29.22			29.22

NYMEX-Henry Hub natural gas price (per Mcf)	$	5.50		$	5.50		$	5.50

Realized natural gas price (per Mcf) (including derivatives)		5.12			5.12			5.12

Realized natural gas price (per Mcf) (excluding derivatives)		4.30			4.30			4.30

Estimated Net Income(1)	$	40,978		$	101,839		$	162,442

Interest expense		3,037			2,653			2,528

Interest income		(257	)		(257	)		(257	)

Depreciation, depletion and amortization		40,536			49,601			58,665

Impairment expenses		—			—			—

Accretion of discount on asset retirement obligations		6,384			6,384			6,384


	Percentage of Forecasted Net Production
	80%			100%			120%
	(in thousands, except per unit amounts)

Exploration expense		192			192			192

Non-cash derivative (gain) / loss(2)		—			—			—

Non-cash incentive compensation		—			—			—

Non-cash (gain) on forgiveness of debt		—			—			—

Non-recurring (gain) / loss(3)		—			—			—


Estimated Adjusted EBITDAX(4)		90,870			160,412			229,954

Cash interest expense		(2,348	)		(1,964	)		(1,839	)

Cash interest income		257			257			257

Exploration expense		(192	)		(192	)		(192	)

Non-recurring (gain) / loss(3)		—			—			—

Development costs		(46,083	)		(46,083	)		(46,083	)


Estimated Cash Available for Distribution(5)	$	42,504		$	112,430		$	182,097

(1)	Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)

(3)	Does not include estimated Non-Cash (Gain) / Loss or Non-Recurring (Gain) / Loss, which cannot be accurately forecasted for future periods.

(4)	Adjusted EBITDAX is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

(5)	Cash available for distribution is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

As reservoir pressures decline, production from a given well or formation decreases. Maintaining or growing our future production and reserves will depend on our ability to continue to replace current production with new reserves. Accordingly, we plan to focus on maintaining reserves through both the drill bit and acquisitions, while maintaining a conservative financial profile. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify and consummate acquisitions. See “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry” for a discussion of these and other risks affecting our proved reserves and production.

Commodity Price Changes

Our major market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production. Pricing for oil, NGLs, and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, NGL, and natural gas production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. While there is a risk we may not be able to realize the full benefits of rising prices, these hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.

The following table shows estimated Adjusted EBITDAX under various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas prices for the twelve months ending September 30, 2023. For the twelve months ending September 30, 2023, we have assumed that commodity derivative contracts will cover (i) 2,752 MBoe, or approximately 40.4% of our estimated total oil production from proved reserves for the twelve months ending September 30, 2023, at a weighted average floor price of $69.64 per Bbl, (ii) 70,940 gallons, or approximately 45.6% of our estimated total natural gas liquids production from proved reserves for the twelve months ending September 30, 2023, at a weighted average floor price of $0.36 per gallon and (iii) 42,535 MMBtu, or approximately 49.6% of our estimated total natural gas production from proved reserves for the twelve months ending September 30, 2023, at a weighted average floor price of $3.75 per MMBtu. In addition, the estimated Adjusted EBITDAX amounts shown below are based on forecasted realized commodity prices that take into account assumptions based on our average historical NYMEX commodity price differentials as set forth in our December 31, 2021 reserve report. We have assumed no changes in our production based on changes in prices. The estimated Adjusted EBITDAX amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions.


	Percentage of Forecasted Prices
	80%		100%		120%
	(in thousands, except per unit amounts)

Forecasted net production:

Oil and condensate (MBbl)		2,485		2,485		2,485

Natural gas (MMcf)		31,319		31,319		31,319

Natural gas liquids (MBbl)		1,352		1,352		1,352


Total (MBoe)		9,057		9,057		9,057

Oil and condensate (Bbl/d)		6,808		6,808		6,808

Natural gas (Mcf/d)		85,805		85,805		85,805

Natural gas liquids (Bbl/d)		3,704		3,704		3,704


Total (Boe per day)		24,814		24,814		24,814

Forecasted prices:

NYMEX-WTI oil price (per Bbl)	$	64.79	$	80.99	$	97.19

Realized oil price (per Bbl) (excluding derivatives)		63.87		80.06		96.25

Realized oil price (per Bbl) (including derivatives)		65.30		74.95		84.59

NYMEX-WTI oil price (per Bbl)	$	64.79	$	80.99	$	97.19

Realized natural gas liquids price (per Mcf) (excluding derivatives)		24.06		30.07		36.08

Realized natural gas liquids price (per Mcf) (including derivatives)		23.20		29.22		35.23

NYMEX-Henry Hub natural gas price (per MMBtu)	$	4.40	$	5.50	$	6.60


	Percentage of Forecasted Prices
	80%			100%			120%
	(in thousands, except per unit amounts)

Realized natural gas price (per Mcf) (excluding derivatives)		4.06			5.12			6.19

Realized natural gas price (per Mcf) (including derivatives)		3.74			4.30			4.83

Estimated Net Income(1)	$	57,922		$	101,839		$	145,036

Interest expense		2,808			2,653			2,595

Interest income		(257	)		(257	)		(257	)

Depreciation, depletion and amortization		49,601			49,601			49,601

Impairment expenses		—			—			—

Accretion of discount on asset retirement obligations		6,384			6,384			6,384

Exploration expense		192			192			192

Non-cash derivative (gain) / loss(2)		—			—			—

Non-cash incentive compensation		—			—			—

Non-cash (gain) on forgiveness of debt		—			—			—

Non-recurring (gain) / loss(3)		—			—			—


Estimated Adjusted EBITDAX(4)		116,650			160,412			203,551

Cash interest expense		(2,119	)		(1,964	)		(1,906	)

Cash interest income		257			257			257

Exploration expense		(192	)		(192	)		(192	)

Non-recurring (gain)/loss(3)		—			—			—

Development costs		(46,083	)		(46,083	)		(46,083	)


Estimated Cash Available for Distribution(5)	$	68,513		$	112,430		$	155,627

(1)	Includes the forecasted effect of cash settlements of commodity derivative instruments. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.

(2)

(3)	Does not include estimated Non-Cash (Gain) / Loss or Non-Recurring (Gain) / Loss, which cannot be accurately forecasted for future periods.

(4)	Adjusted EBITDAX is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

(5)	Cash available for distribution is defined in “Prospectus Summary—Non-GAAP Financial Measures.”

If NYMEX oil, natural gas liquids and natural gas prices decline, our estimated Adjusted EBITDAX would not decline proportionately for two reasons: (1) the effects of our commodity derivative contracts; and (2) production taxes, which are calculated as a percentage of our oil, natural gas liquids and natural gas revenues, excluding the effects of our commodity derivative contracts, and which decrease as commodity prices decline. Furthermore, we have assumed no decline in estimated production or oil, natural gas liquids and natural gas operating costs during the twelve months ending September 30, 2023. However, over the long-term, a sustained decline in prices would likely lead to a decline in production and operating costs, as well as a reduction in our realized oil, natural gas liquids and natural gas prices. Therefore, the foregoing table is not illustrative of all of the potential effects of changes in commodity prices for periods subsequent to September 30, 2023.

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 60 days after the end of each quarter (other than the fourth quarter) and within 90 days after the end of the fourth quarter, beginning with the quarter ending March 31, 2023, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our cash distribution for the period from the closing of this offering through March 31, 2023, based on the actual length of that period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

•

less, the amount of cash reserves established by our general partner to:

•

provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distributions to our unitholders for any one or more of the next four quarters;

•

plus, all cash and cash equivalents on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter;

•

plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination resulting from working capital borrowings made after the end of the quarter.

Methods of Distribution

We intend to distribute available cash to our unitholders, pro rata. Our partnership agreement permits, but does not require, us to borrow funds to make distributions to our unitholders. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future acquire common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment (or establishing a reserve for payment) of our creditors. We will distribute any remaining proceeds to our unitholders, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The selected historical consolidated financial data set forth below as of and for each of the years ended December 31, 2021 and 2020 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected historical consolidated financial data set forth below as of September 30, 2022 and for the nine months ended September 30, 2022 and 2021 are derived from our unaudited financial statements and related notes included elsewhere in this prospectus.

The selected unaudited pro forma financial data as of September 30, 2022 and for the nine months ended September 30, 2022 and the year ended December 31, 2021 are derived from the unaudited pro forma condensed financial statements of TXO Energy Partners included elsewhere in this prospectus. Our unaudited pro forma condensed financial statements give pro forma effect to the following:

•

the Reorganization Transactions (including the one-for 25.33 Reverse Unit Split); and

•

the issuance and sale by us to the public of 5,000,000 common units in this offering and the application of the net proceeds as described in “Use of Proceeds.”

The unaudited pro forma historical financial data are presented for illustrative purposes only and are not necessarily indicative of the financial position that would have existed or the financial results that would have occurred if this offering and the acquisition of the Vacuum Properties had been consummated on the dates indicated, nor are they necessarily indicative of the financial position or results of our operations in the future. The pro forma adjustments, as described in the notes to the unaudited pro forma condensed combined financial statements, are preliminary and based upon currently available information and certain assumptions that our management believes are reasonable. The selected historical consolidated financial data are qualified in their entirety by, and should be read in conjunction with, the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included in this prospectus and the consolidated financial statements and related notes and other financial information included in this prospectus. Among other things, those historical financial statements and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the following information. Historical results are not necessarily indicative of results that may be expected for any future period.


	TXO Energy Partners Historical												TXO Energy Partners Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,						Year Ended December 31			Nine Months Ended September 30,
	2021			2020			2022			2021			2021			2022
(in thousands, except per unit amounts)	(unaudited)

Statement of Operations Data:

Revenues:

Oil and condensate	$	69,971		$	59,070		$	120,703		$	40,061		$	118,186		$	120,703

Natural gas liquids	$	27,875		$	8,660		$	29,268		$	18,086		$	29,810		$	29,268

Natural gas	$	130,498		$	41,034		$	54,067		$	80,783		$	130,676		$	54,067


Total revenues(1)	$	228,344		$	108,764		$	204,038		$	138,930		$	278,672		$	204,038


Expenses:

Production	$	69,256		$	49,146		$	93,961		$	45,833		$	99,406		$	93,961

Exploration	$	124		$	55		$	281		$	81		$	124		$	281

Taxes, transportation and other	$	58,040		$	27,509		$	72,993		$	37,941		$	63,102		$	72,993

Depreciation, depletion and amortization	$	39,889		$	42,322		$	30,329		$	28,054		$	47,650		$	30,329

Impairment	$	—		$	134,097		$	—		$	—		$	—		$	—

Accretion of discount on asset retirement obligations	$	4,670		$	3,940		$	4,508		$	3,513		$	4,962		$	4,508

General and administrative	$	12,175		$	6,995		$	572		$	3,646		$	12,175		$	572


Total expenses	$	184,154		$	264,064		$	202,644		$	119,068		$	227,419		$	202,644


Operating income (loss)	$	44,190		$	(155,300	)	$	1,394		$	19,862		$	51,253		$	1,394


Other income (expenses):

Other income	$	14,139		$	72		$	18,677		$	9,128		$	17,312		$	18,677

Interest income	$	16		$	194		$	68		$	11		$	16		$	68

Interest expense	$	(5,870	)	$	(8,204	)	$	(5,526	)	$	(3,722	)	$	(3,923	)	$	(3,032	)


Total other income (expenses)	$	8,285		$	(7,938	)	$	13,219		$	5,417		$	13,405		$	15,713


Net income (loss)	$	52,475		$	(163,238	)	$	14,613		$	25,279		$	64,658		$	17,107

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	TXO Energy Partners Historical												TXO Energy Partners Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,						Year Ended December 31		Nine Months Ended September 30,
	2021			2020			2022			2021			2021		2022
(in thousands, except per unit amounts)	(unaudited)

Net income per limited partner unit:

Basic	$	2.10		$	(6.53	)	$	0.58		$	1.01		$	2.16	$	0.57


Diluted	$	2.10		$	(6.53	)	$	0.58		$	1.01		$	2.12	$	0.56


Weighted average number of limited partner units outstanding (basic and diluted):

Basic		25,000			25,000			25,000			25,000			30,000		30,000


Diluted		25,000			25,000			25,000			25,000			30,545		30,545


Other Financial Data:

Adjusted EBITDAX	$	85,348		$	32,322		$	118,628		$	52,530		$	103,637	$	118,628

Cash Available for Distribution	$	72,348		$	20,132		$	105,538		$	40,610		$	92,586	$	108,032

Cash Flow Data:

Net cash provided by (used in):

Operating activities	$	73,726		$	18,964		$	103,668		$	47,000

Investing activities	$	(227,801	)	$	(16,718	)	$	(70,443	)	$	(21,415	)

Financing activities	$	139,689		$	14,067		$	(29,624	)	$	(35,089	)

Balance Sheet Data (at period end):

Total assets	$	832,820		$	623,940		$	901,855		$	611,037				$	901,855

Total long-term debt	$	152,100		$	151,252		$	132,100		$	107,100				$	44,100

Partners’ capital	$	541,359		$	303,268		$	549,492		$	327,937				$	637,492

(1)	Includes the effect of unrealized losses on commodity derivatives.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our audited financial statements as of and for the years ended December 31, 2020 and 2021 and the nine months ended September 30, 2022, and related notes thereto, included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. These forward-looking statements are dependent upon events, risks and uncertainties that may be outside of our control. Our actual results could differ materially from those disclosed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Unless otherwise indicated, throughout this discussion the term “MBoe” refers to thousands of barrels of oil equivalent quantities produced for the indicated period, with natural gas and NGL quantities converted to Bbl on an energy equivalent ratio of six Mcf to one barrel of oil.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas and natural gas liquid reserves in North America. Our properties are predominately located in the Permian Basin of New Mexico and Texas and the San Juan Basin of New Mexico and Colorado.

As significant owners of the Company, our management has sought to build a business that can generate substantial free cash flow and support distributions to our unitholders. We have grown the business steadily through thoughtful acquisitions and the disciplined development of our assets. We believe we have a proven track record of responsible capital stewardship and risk mitigation. We strive to make every investment—whether acquiring additional assets or the development of our existing portfolio—with the goal of maintaining and, over time, modestly increasing cash flows to drive increased distributions to our unitholders.

We seek to maintain a flat to low growth production profile through a combination of low-risk development and exploitation of our existing properties, which is generally funded by cash flow from operating activities, and acquisitions of primarily producing properties. To date we have been successful in offsetting the natural decline in production from reservoir depletion through acquisitions and drilling, adding more reserves than we produce. Funding sources for our acquisitions have included proceeds from bank borrowings, cash from our partners and cash flow from operating activities. Our development budget was approximately $30.0 million for 2022 and is approximately $30.0 million for 2023.

Market Outlook

The oil and natural gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2021 through December 31, 2022, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $23.86 per MMBtu, respectively, and a low of $47.62 per Bbl

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and $2.43 per MMBtu, respectively. Oil prices steadily increased through 2021 due to continued recovery in demand before increasing drastically in the first half of 2022 due to further demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Since the Russia-Ukraine conflict first commenced, WTI crude oil prices have trended higher, rising from $92.81 per Bbl on February 24, 2022 to a high of $123.70 per Bbl in March 2022 before declining to $80.26 per Bbl as of December 30, 2022. Natural gas prices reached a high of $9.85 per MMbtu in August 2022 before declining to $4.48 per MMbtu as of December 30, 2022. These prices have been very volatile and experience large swings, sometimes on a day-to-day or week-to-week basis.

We expect the crude oil and natural gas markets will continue to be volatile in the future. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production. Please see “Risk Factors—Risks Related to the Natural Gas, NGL and Oil Industry and Our Business—Commodity prices are volatile—A sustained decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2022, due to a substantial increase in the money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 7.1% in November 2022 and fell to 6.5% in December 2022. Global, industry-wide supply chain disruptions have resulted in widespread shortages of labor, materials and services. Such shortages have resulted in our facing significant cost increases for labor, materials and services. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and annual wage increases have increased our operating costs for the nine months ended September 30, 2022 compared to the same period in 2021. We also may face shortages of these commodities and labor, which may prevent us from executing on our development plan. We do not expect these shortages and cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent inflation remains elevated, we may experience further cost increases in our operations, including costs for drill rigs, workover rigs, tubulars and other well equipment, as well as increased labor costs. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

We are taking actions to mitigate supply chain and inflationary pressures. We have pre-purchased pipe necessary to drill the remainder of our planned development for 2022. We are working closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations. However, these mitigation efforts may not succeed or be insufficient.

Sources of Our Revenue

Our revenues are derived from the sale of our oil, NGLs and natural gas production. Our revenues are influenced by production volumes and realized prices on the sale of oil, NGLs, and natural gas including the effect of our commodity derivative contracts. We sell oil, natural gas and NGLs at a specific delivery point, pay transportation to third parties and receive proceeds from the purchaser with no transportation deduction. As a result, we record transportation costs we pay to

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third parties as taxes, transportation and other deductions. Pricing of commodities is subject to supply and demand as well as to seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table presents the breakdown of our revenues including both the realized and unrealized effects of our commodity derivative contracts for the periods specified below:


	For the Year Ended December 31,						For the Nine Months Ended September 30,
	2021			2020			2022			2021

Crude oil sales		31	%		54	%		59	%		29	%

Natural gas sales		57	%		38	%		27	%		58	%

Natural gas liquid sales		12	%		8	%		14	%		13	%

The following table presents that breakdown of our revenues for the periods specified below excluding the unrealized effects of our commodity derivative contracts.


	For the Year Ended December 31,						For the Nine Months Ended September 30,
	2021			2020			2022			2021

Crude oil sales		32	%		55	%		48	%		29	%

Natural gas sales		56	%		37	%		40	%		58	%

Natural gas liquid sales		12	%		8	%		12	%		13	%

Revenue excluding the unrealized effects of commodity derivative contracts is a non-GAAP supplemental financial measure that management and external users of our combined financial statements, such as investors, lenders and others (including industry analysts and rating agencies who will be using such measure), may use for the periods presented to more effectively evaluate our operating performance and our results of operation from period to period without giving effect to non-cash gains and losses. The GAAP measures most directly comparable to revenue excluding the unrealized effects of commodity derivative contracts is GAAP revenue. You should not consider revenue excluding the unrealized effects of commodity derivative contracts in isolation or as a substitute for analysis of our results as reported under GAAP.

Production volumes

Our ability to generate sufficient cash from operations to pay cash distributions to unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. Production volumes directly impact our revenue. Any negative effect on production volumes could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution. The following table presents historical production volumes for our properties for the periods specified below:

The following table presents historical production volumes for our properties for the periods specified below:


	For the Year Ended December 31,				For the Nine Months Ended September 30,
	2021		2020		2022		2021

Oil and condensate (MBbls)		1,033		940		1,605		633

Natural gas liquids (MBbls)		1,089		860		993		798

Natural gas (MMcf)		30,590		22,132		22,522		22,441

Total (MBoe)		7,220		5,489		6,351		5,171

Average net sales (MBoe/day)		20		15		23		19

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Sales volumes directly impact our results of operations. For more information about sales volumes, see “—Historical Results of Operations.”

As reservoir pressures decline, production from a given well or formation decreases. Maintaining or growing our future production and reserves will depend on our ability to continue to replace current production with new reserves. Accordingly, we plan to focus on maintaining reserves through both the drill bit and acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify and consummate acquisitions. See “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry” for a discussion of these and other risks affecting our proved reserves and production.

Realized commodity prices

Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile and currently are at near record-high levels. During the period from January 1, 2021 through September 30, 2022, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $23.86 per MMBtu, respectively, and a low of $47.62 per Bbl and $2.43 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which is redetermined semi-annually. See “—Liquidity and Capital Resources—Revolving credit agreement.”


	For the Year Ended December 31,						For the Nine Months Ended September 30,
	2021			2020			2022		2021

Average prices:

*Oil (Bbl)*

Average NYMEX Price	$	68.11		$	39.32		$	98.25	$	65.04

Average Realized Price (excluding derivatives)	$	67.41		$	37.11		$	98.27	$	63.27

Average Realized Price (including derivatives)	$	67.74		$	62.84		$	75.22	$	63.27

Differential to NYMEX	$	(0.70	)	$	(2.21	)	$	0.02	$	(1.77)

*Natural Gas (Mcf)*

Average NYMEX Price	$	3.89		$	2.03		$	6.74	$	3.61

Average Realized Price (excluding derivatives)	$	4.00		$	1.89		$	6.32	$	3.60

Average Realized Price (including derivatives)	$	4.27		$	1.85		$	2.40	$	3.60

Differential to NYMEX	$	0.11		$	(0.14	)	$	(0.42)	$	(0.01)

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	For the Year Ended December 31,					For the Nine Months Ended September 30,
	2021		2020			2022		2021

*Natural gas liquids (Bbl)*

Average Realized Price (excluding derivatives)	$	25.16	$	10.07		$	37.94	$	22.66

Average Realized Price (including derivatives)	$	25.60	$	10.07		$	29.47	$	22.66

High and low NYMEX prices:

*Oil (Bbl)*

High	$	84.65	$	63.27		$	123.70	$	75.45

Low	$	47.62	$	(37.63	)	$	76.08	$	47.62

*Natural gas (Mcf)*

High	$	23.86	$	3.14		$	9.85	$	23.86

Low	$	2.43	$	1.33		$	3.73	$	2.43

Hedging activities

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our production. In most of our current positions, our hedging activity may also reduce our ability to benefit from increases in commodity prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices, and conversely, we will recognize gains to the extent our derivatives contract prices are higher than market prices. Our policy is to opportunistically hedge a portion of our production at commodity prices management deems attractive. We are also subject to certain hedging requirements pursuant to our Credit Facility. See “—Liquidity and Capital Resources—Revolving credit agreement.” While there is a risk we may not be able to realize the full benefits of rising prices, management may continue its hedging strategy because of the benefits of predictable, stable cash flows. See “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

The price we receive for our oil and natural gas production is generally less than the NYMEX prices because of adjustments for basis, relative quality and other factors. We have entered into basis swap agreements that effectively fix the basis adjustment for our delivery locations.

In the year ended December 31, 2021, all of our hedging activities increased oil revenue $0.3 million, NGL revenue $0.5 million and gas revenue $8.2 million. In the year ended December 31, 2020, all of our hedging activities increased oil revenue $24.2 million and decreased gas revenue $0.9 million. In the nine months ended September 30, 2022, all of our hedging activities decreased oil revenue $37.0 million, NGL revenue $8.4 million and gas revenue $88.2 million. In the nine months ended September 30, 2021, all of our hedging activities had no effect on revenue.

The following tables summarize our open oil, NGL and natural gas hedging production as of September 30, 2022. Prices to be realized for hedged production will be less than these NYMEX prices because of location, quality and other adjustments.


Crude Oil—Swaps Production Period	Bbls per Day		Weighted Average NYMEX Price per Bbl

October 2022—December 2022		3,500	$	71.28

January 2023—December 2023		2,500	$	68.87

January 2024—June 2024		2,000	$	63.27

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Crude Oil Basis Swaps—West Texas Midland Production Period	Bbls per Day		Weighted Average Sell Basis Price per Bbl (a)

October 2022—December 2022		3,000	$	0.55

January 2023—December 2023		3,000	$	1.05

(a)	Increases to NYMEX oil price for delivery location


Crude Oil—Roll Component Production Period	Bbls per Day		Weighted Average Roll Price per Bbl (a)

October 2022—December 2022		5,000	$	0.50

January 2023—December 2023		1,000	$	0.68

(a)	Increases to NYMEX oil price for roll component


Natural Gas Liquids—Swaps Production Period	Gallons per Day		Weighted Average NGL OPIS Price per Gallon
Ethane

October 2022—December 2022		63,000	$	0.33

January 2023—December 2023		63,000	$	0.27

January 2024—June 2024		63,000	$	0.23
Propane

October 2022—December 2022		31,500	$	1.01


Natural Gas—Swaps Production Period	MMBtu per Day		Weighted Average NYMEX Price per MMBtu

October 2022—December 2022		45,000	$	4.23

January 2023—December 2023		35,000	$	3.51

January 2024—June 2024		30,000	$	3.26


Natural Gas—Collars Production Period			Weighted Average NYMEX Price per MMBtu
Natural Gas—Collars Production Period	MMBtu per Day		Floor		Ceiling

October 2022—December 2022		15,000	$	3.50	$	5.85

January 2023—March 2023		5,000	$	5.00	$	9.85

January 2024—June 2024		5,000	$	3.75	$	7.25


Natural Gas Basis Swaps—San Juan Production Period	MMBtu per Day		Weighted Average Sell Basis Price per MMBTU (a)

October 2022—December 2022		70,000	$	0.22

January 2023—December 2023		20,000	$	0.15

(a)	Reductions to NYMEX gas price for delivery location

Principal Components of Our Cost Structure

Production expenses

Production expenses are the costs incurred in the operation of producing properties and include workover costs. Expenses for labor, overhead and repairs and maintenance comprise the most significant components of production expenses. Lease operating expenses do not include

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general and administrative expenses or severance or ad valorem taxes. We evaluate production expenses on a per Boe basis to monitor changes in production expenses to determine that costs are at an acceptable level. We monitor our operations to ensure that we are incurring lease operating expenses at an acceptable level. Although we strive to reduce our lease operating expenses, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate and develop our properties or make acquisitions of properties.

Taxes, transportation, and other expenses

Taxes, transportation, and other expenses consist primarily of gathering and processing fees, transportation costs, severance taxes, and ad valorem taxes. Gathering, processing and transportation costs are recognized when control of the natural gas we sell occurs at the tailgate of the processing plant. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by state or local taxing authorities. In general, the severance taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. We evaluate taxes, transportation, and other expense on a per Boe basis to monitor costs to ensure that they are at acceptable levels. Taxes, transportation, and other expenses can also be influenced by acquisitions, commodity prices, changes in values of our properties, sales mix and acquisitions.

Depletion, depreciation, and amortization

Depreciation, depletion, and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. We follow the successful efforts method of accounting, capitalizing costs of successful acquisitions and exploratory wells, which are then allocated to each unit of production using the unit of production method, and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. We generally pursue acquisition and development of proved reserves as opposed to exploration activities. Changes in DD&A are a result of production and changes in the estimated reserves during the period.

General and administrative expenses

General and administrative expenses consist primarily of personnel related costs and are partially offset by certain reimbursements of overhead expenses. In connection with the consummation of this offering, we expect to incur additional costs related to being a public company. However, we do not expect to experience a material change in our cash cost structure, other than as set forth below under “Factors Affecting the Comparability of Our Financial Condition and Results of Operations.”

Interest expense

Interest expense is primarily a result of interest on our borrowings on our Credit Facility to fund operations and acquisitions of properties as well as the amortization of debt issuance costs associated with these borrowings. Interest expense can fluctuate with our level of indebtedness as well as changes in interest rates.

Income tax

Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. While we do not pay income tax in Texas, we are subject to Texas franchise taxes.

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How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our operations, including:

•

production volumes;

•

realized prices on the sale of oil, NGLs and natural gas;

•

production expenses;

•

acquisition and development expenditures

•

Adjusted EBITDAX; and

•

Cash Available for Distribution.

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) before (1) interest income, (2) interest expense, (3) depreciation, depletion and amortization, (4) impairment expenses, (5) accretion of discount on asset retirement obligations, (6) exploration expenses, (7) unrealized (gain) losses on commodity derivative contracts, (8) non-cash incentive compensation, (9) non-cash (gain) loss on forgiveness of debt and (10) certain other non-cash expenses.

Adjusted EBITDAX is not a measure of net income as determined by U.S. GAAP. Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate the financial performance of our assets from period to period and against our peers without regard to financing methods or capital structure.

Cash Available for Distribution

Although we have not quantified cash available for distribution on a historical basis, after the closing of this offering, we intend to use cash available for distribution to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as Adjusted EBITDAX less cash interest expense, exploration expense and development costs. Development costs includes all of our capital expenditures made for oil and gas properties, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances.

You should not infer from our presentation of Adjusted EBITDAX that its results will be unaffected by unusual or non-recurring items. You should not consider Adjusted EBITDAX or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDAX and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDAX and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, primarily for the following reasons:

Property acquisitions

We have completed three significant acquisitions in the past two years that affect the comparability of results of operations between 2020, 2021 and 2022 to some extent. We intend to continue to grow our operations through prudent acquisitions. Additionally, it is possible that we will effect divestitures of certain of our assets. We may enter into acquisitions and/or divestitures in the ordinary course of business that may affect our future operations, including our revenues and operating expenses. The following is a summary of our significant acquisition activity that occurred from the beginning of 2020 to the date of this prospectus:

•

San Juan Acquisition. The acquisition in June 2020 of producing properties in the San Juan Basin of New Mexico and Colorado for approximately $10.2 million.

•

Vacuum Acquisition. The acquisition in November 2021 of producing properties and a gas processing plant in the Permian Basin of New Mexico and CO₂ assets in Colorado for approximately $179.3 million.

•

Andrews Parker Acquisition. The acquisition in December 2021 of producing properties in the Permian Basin of Texas for approximately $43.8 million.

•

Additional Interest Vacuum Acquisition. The acquisition in August 2022 of additional interest in our producing properties and a gas processing plant in the Permian Basin of New Mexico for approximately $52.6 million.

Supply, demand, market risk and their impact on oil prices.

The oil industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2021 through December 31, 2022, prices for crude oil reached a high of $123.70 per Bbl and a low of $47.62 per Bbl. Crude oil prices were impacted by a variety of factors affecting current and expected supply and demand dynamics, including: strong demand for crude oil, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Since the Russia-Ukraine conflict first commenced, WTI crude oil prices have trended higher, rising from $92.81 per Bbl on February 24, 2022 to a high of $123.70 per Bbl in March 2022 before declining to $80.26 as of December 30, 2022. Natural gas prices reached a high of $9.85 per MMbtu in August 2022 before declining to $4.48 per MMbtu as of December 30, 2022. These prices experience large swings, sometimes on a day-to-day or week-to-week basis.

Other factors impacting supply and demand include weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar as well as other factors, the majority of which are outside of our control. In addition to these uncontrollable influences, there is an ongoing shift of relaxing COVID-19 containment measures worldwide, which may increase economic activity and energy demand. As a result of these external factors, we expect global commodity price volatility will continue throughout 2023. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production. Please see “Risk Factors—Risks Related to the Natural Gas, NGL and Oil Industry and Our Business—Commodity prices are volatile—A sustained decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

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Public company expenses

Upon the completion of this offering, we expect to incur incremental non-recurring costs related to our transition to a publicly traded partnership, including the costs of this initial public offering and the costs associated with the initial implementation of our internal control implementation and testing. We also expect to incur additional significant and recurring expenses as a publicly traded partnership, including costs associated with the employment of additional personnel, compliance under the Exchange Act, annual and quarterly reports to shareholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. The direct, incremental general and administrative expenses are not included in our historical or pro forma financial statements.

Derivatives

Impairment

We evaluate our producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Results of Operations

Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021


	September 30,
	2022		2021
	(in thousands)

Revenues:

Oil and condensate sales	$	120,703	$	40,061

Natural gas liquids sales	$	29,268	$	18,086

Gas sales	$	54,067	$	80,783


Total revenues	$	204,038	$	138,930


Expenses:

Production expenses	$	93,961	$	45,833

Exploration expenses	$	281	$	81

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	September 30,
	2022			2021
	(in thousands)

Taxes, transportation, and other	$	72,993		$	37,941

Depreciation, depletion, and amortization	$	30,329		$	28,054

Accretion of discount in asset retirement obligations	$	4,508		$	3,513

General and administrative	$	572		$	3,646


Total expenses	$	202,644		$	119,068


Operating income:	$	1,394		$	19,862


Other income (expense):

Other income	$	18,677		$	9,128
Interest income	$	68		$	11

Interest expense	$	(5,526	)	$	(3,722	)


Total other income	$	13,219		$	5,417


Net income:	$	14,613		$	25,279

The following table provides a summary of our sales volumes, average prices (both including and excluding the effects of derivatives) and operating expenses on a per Boe basis for the periods indicated:


	Nine Months Ended September 30,
	2022		2021

Sales:

Oil and condensate sales (MBbls)		1,605		633

Natural gas liquids sales (MBbls)		993		798

Natural gas sales (MMcf)		22,522		22,441


Total (MBoe)		6,351		5,171

Total (MBoe/d)		23		19

Average sales prices:

Oil and condensate excluding the effects of derivatives (per Bbl)	$	98.27	$	63.27

Oil and condensate (per Bbl) (1)	$	75.22	$	63.27

Natural gas liquids excluding the effects of derivatives (per Bbl)	$	37.94	$	22.66

Natural gas liquids (per Bbl) (2)	$	29.47	$	22.66

Natural gas excluding the effects of derivatives (per Mcf)	$	6.32	$	3.60

Natural gas (per Mcf) (3)	$	2.40	$	3.60

Expense per Boe:

Production	$	14.79	$	8.86

Taxes, transportation and other	$	11.49	$	7.34

Depreciation, depletion and amortization	$	4.78	$	5.42

General and administrative expenses	$	0.09	$	0.71

(1)

Oil and condensate prices include both realized and unrealized losses from derivatives. The unrealized losses were $8.3 million for the nine months ended September 30, 2022 and $0.0 million for the nine months ended September 30, 2021. The realized losses were $28.7 million for the nine months ended September 30, 2022 and $0.0 million for the nine months ended September 30, 2021.

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(2)

Natural gas liquids prices include both realized and unrealized losses from derivatives. The unrealized losses were $3.4 million for the nine months ended September 30, 2022 and $0.0 million for the nine months ended September 30, 2021. The realized losses were $5.0 million for the nine months ended September 30, 2022 and $0.0 million for the nine months ended September 30, 2021.

(3)

Natural gas prices include both realized and unrealized losses from derivatives. The unrealized losses were $51.7 million for the nine months ended September 30, 2022 and $0.0 million for the nine months ended September 30, 2021. The realized losses were $36.5 million for the nine months ended September 30, 2022 and $0.0 million for the nine months ended September 30, 2021.

Revenues

Revenues increased $65.1 million, or 47%, from $138.9 million for the nine months ended September 30, 2021 to $204.0 million for the nine months ended September 30, 2022. The increase was primarily attributable to an increase in production of 1,180 MBoe primarily as a result of additional production from the acquired Vacuum properties of 957 MBoe and Andrews Parker properties of 253 Mboe, respectively, resulting in an increase in revenue of $103.4 million and an increase in the average selling price, excluding the effects of derivatives, on oil of 55% resulting in an increase in revenue of $22.2 million, on NGLs of 67% resulting in an increase in revenue of $12.2 million, and on natural gas of 76% resulting in an increase in revenue of $61.0 million. These increases were partially offset by losses on our hedging activity of $133.7 million, of which $63.4 million were unrealized losses and $70.3 million were realized losses.

Production expenses

Production expenses increased $48.1 million, or 105%, from $45.8 million for the nine months ended September 30, 2021 to $93.9 million for the nine months ended September 30, 2022. The increase is primarily attributable to the increased production associated with the addition of the Vacuum and Andrews Parker properties of $40.6 million as well as increased maintenance costs and other cost increases.

On a per unit basis, production expenses increased from $8.86 per Boe sold for the nine months ended September 30, 2021 to $14.79 per Boe sold for the nine months ended September 30, 2022. The increase is primarily related to the increased costs per Boe from the acquired Vacuum and Andrews Parker properties due to the acquired properties having a higher percentage of oil production, which is more expensive on a Boe basis than natural gas production. Additionally, increased maintenance costs and other cost increases contributed to the increase per Boe.

Taxes, transportation, and other

Taxes, transportation, and other increased $35.1 million, or 92%, from $37.9 million for the nine months ended September 30, 2021 to $73.0 million for the nine months ended September 30, 2022. The increase is primarily attributable to the increased production associated with the addition of the Vacuum and Andrews Parker properties of $17.0 million as well as an increase in oil, NGLs, and natural gas prices.

On a per unit basis, taxes, transportation, and other increased from $7.34 per Boe sold for the nine months ended September 30, 2021 to $11.49 per Boe sold for the nine months ended September 30, 2022. The increase is primarily related to the higher commodity prices and change in production mix.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization increased $2.3 million, or 8%, from $28.0 million for the nine months ended September 30, 2021 to $30.3 million for the nine months ended September 30, 2022. The increase is primarily attributable to the increased production associated

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with the addition of the Vacuum and Andrews Parker properties in the fourth quarter of 2021 of $9.5 million partially offset by a reduction of $7.2 million from our other assets as a result of a lower average DD&A rate and decreased production.

On a per unit basis, depreciation, depletion, and amortization decreased from $5.52 per Boe sold for the nine months ended September 30, 2021 to $4.78 per Boe sold for the nine months ended September 30, 2022. The decrease is primarily related to changes in reserves.

General and administrative

General and administrative (“G&A”) expenses decreased $3.1 million, or 84%, from $3.6 million for the nine months ended September 30, 2021 to $0.6 million for the nine months ended September 30, 2022. The decrease is primarily attributable to a reduction of $5.9 million from headcount reductions partially offset by $2.7 million of decreased cost recoveries.

On a per unit basis, G&A expense decreased from $0.71 per Boe sold for the nine months ended September 30, 2021 to $0.09 per Boe sold for the nine months ended September 30, 2022. The decrease is primarily related to decreased costs and increased production partially offset by decreased cost recovery.

Other income

Other income increased $9.6 million, or 105%, from $9.1 million for the nine months ended September 30, 2021 to $18.7 million for the nine months ended September 30, 2022. The increase is primarily attributable to the recognition of $18.6 million of CO₂ and plant income related to the acquired Vacuum properties partially offset by the absence of the forgiveness of debt of $9.2 million under the U.S. Government’s Paycheck Protection Program from the Small Business Administration. The CO₂ and plant income is ancillary to the operations of the Vacuum properties.

Interest expense

Interest expense increased $1.8 million, or 48%, from $3.7 million for the nine months ended September 30, 2021 to $5.5 million for the nine months ended September 30, 2022. The increase is primarily attributable to the additional borrowings to fund the Chevron Acquisitions, the Additional Interest Vacuum Acquisition and a higher interest rate.

Year Ended December 31, 2021 Compared to the Year Ended December 31, 2020


	December 31,
	2021		2020
	(in thousands)

Revenues:

Oil and condensate sales	$	69,971	$	59,070

Natural gas liquids sales	$	27,875	$	8,660

Gas sales	$	130,498	$	41,034


Total revenues	$	228,344	$	108,764


Expenses:

Production expenses	$	69,256	$	49,146

Exploration expenses	$	124	$	55

Taxes, transportation, and other	$	58,040	$	27,509

Depreciation, depletion, and amortization	$	39,889	$	42,322

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	December 31,
	2021			2020
	(in thousands)

Impairment	$	—		$	134,097

Accretion of discount in asset retirement obligations	$	4,670		$	3,940

General and administrative	$	12,175		$	6,995


Total expenses	$	181,754		$	264,064


Operating income (loss):	$	44,190		$	(155,300	)


Other income (expense):

Other income	$	14,139		$	72

Interest income	$	16		$	194

Interest expense	$	(5,870	)	$	(8,204	)


Total other income (expense)	$	8,285		$	(7,938	)


Net income (loss):	$	52,475		$	(163,238	)


	Year Ended December 31,
	2021		2020

Sales:

Oil and condensate sales (MBbls)		1,033		940

Natural gas liquids sales (MBbls)		1,089		860

Natural gas sales (MMcf)		30,590		22,132


Total (MBoe)		7,220		5,489

Total (MBoe/d)		20		15

Average sales prices:

Oil and condensate excluding the effects of derivatives (per Bbl)	$	67.41	$	37.11

Oil and condensate (per Bbl) (1)	$	67.74	$	62.84

Natural gas liquids excluding the effects of derivatives (per Bbl)	$	25.16	$	10.07

Natural gas liquids (per Bbl) (2)	$	25.60	$	10.07

Natural gas excluding the effects of derivatives (per Mcf)	$	4.00	$	1.89

Natural gas (per Mcf) (3)	$	4.27	$	1.85

Expense per Boe:

Production expenses	$	9.59	$	8.95

Taxes, transportation and other	$	8.04	$	5.01

Depreciation, depletion and amortization	$	5.52	$	7.71

General and administrative expenses	$	1.69	$	1.27

(1)

Oil and condensate prices include both realized and unrealized gains and losses from derivatives. The unrealized portion were gains of $0.3 million for the year ended December 31, 2021, and were losses of $3.0 million for the year ended December 31, 2020. The realized gains were $0.0 million for the year ended December 31, 2021 and $27.2 million for the year ended December 31, 2020.

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(2)	Natural gas liquids prices include unrealized gains from derivatives. The unrealized gains were $0.5 million for the year ended December 31, 2021 and $0.0 million for the year ended December 31, 2020.

(3)

Natural gas prices include both realized and unrealized gains and losses from derivatives. The unrealized gains were $8.2 million for the year ended December 31, 2021 and $0.1 million for the year ended December 31, 2020. The realized losses were $0.0 million for the year ended December 31, 2021 and $1.0 million for the year ended December 31, 2020.

Revenues

Revenues increased $119.6 million, or 110%, from $108.8 million for the year ended December 31, 2020 to $228.3 million for the year ended December 31, 2021. The increase was primarily attributable to an increase in the average selling price, excluding the effects of derivatives, on oil of 82%, resulting in an increase in revenue of $28.5 million, on NGLs of 150%, resulting in an increase in revenue of $13.0 million, and on natural gas of 111%, resulting in an increase in revenue of $46.6 million. The increase was also attributable to an increase in production of 1,731 MBoe primarily as a result of additional production from the acquired San Juan properties of 1,723 MBoe and Vacuum properties of 177 MBoe partially offset by decreased production in our other properties, resulting in an increase in revenue of $45.8 million partially offset by decreased gains on our hedging activity of $14.3 million. The $14.3 million decrease from our hedging activity includes a decrease in the realized portion of $26.2 million partially offset by an increase in the unrealized portion of $11.9 million.

Production expenses

Production expenses increased $20.1 million, or 41%, from $49.1 million for the year ended December 31, 2020 to $69.3 million for the year ended December 31, 2021. The increase is primarily attributable to the increased production associated with the addition of the San Juan properties of $12.7 million and the Vacuum properties of $5.5 million as well as increased maintenance and well work costs.

On a per unit basis, production expenses increased from $8.95 per Boe sold for the year ended December 31, 2020 to $9.59 per Boe sold for the year ended December 31, 2021. The increase is primarily related to the increased costs per Boe from the acquired Vacuum properties as well as the increased maintenance and well work costs.

Taxes, transportation, and other

Taxes, transportation, and other increased $30.5 million, or 111%, from $27.5 million for the year ended December 31, 2020 to $58.0 million for the year ended December 31, 2021. The increase is primarily attributable to the increased production associated with the addition of the San Juan properties of $23.6 million and the Vacuum properties of $2.7 million as well as an increase in oil, NGLs, and natural gas prices.

On a per unit basis, taxes, transportation, and other increased from $5.01 per Boe sold for the year ended December 31, 2020 to $8.04 per Boe sold for the year ended December 31, 2021. The increase is primarily related to the higher commodity prices and change in production mix.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization decreased $2.4 million, or 6%, from $42.3 million for the year ended December 31, 2020 to $39.9 million for the year ended December 31, 2021. The decrease is primarily attributable to a reduction of $7.0 million from our other assets as a result of lower production and lower rate, partially offset by increased production associated with the addition of the San Juan properties of $3.3 million and Vacuum properties of $1.3 million.

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On a per unit basis, depreciation, depletion, and amortization decreased from $7.71 per Boe sold for the year ended December 31, 2020 to $5.52 per Boe sold for the year ended December 31, 2021. The decrease is primarily related to changes in production mix and the effect of the 2020 impairment discussed below.

Impairment of oil and gas properties

For the year ended December 31, 2020, we recognized an impairment of long-lived assets of $134.1 million for our assets primarily due to a lower net commodity price environment for some of our oil and natural gas assets.

General and administrative

General and administrative (“G&A”) expenses increased $5.2 million, or 74%, from $7.0 million for the year ended December 31, 2020 to $12.2 million for the year ended December 31, 2021. The increase is primarily attributable to the increased costs related to the acquired Vacuum properties of $2.7 million as well as decreased COPAS related cost reimbursements.

On a per unit basis, G&A expense increased from $1.27 per Boe sold for the year ended December 31, 2020 to $1.69 per Boe sold for the year ended December 31, 2021. The increase is primarily related to decreased COPAS related cost reimbursements partially offset by increased production.

Other income

Other income increased $14.1 million from $0.1 million for the year ended December 31, 2020 to $14.1 million for the year ended December 31, 2021. The increase is primarily attributable to forgiveness of debt of $9.2 million under the U.S. Government’s Paycheck Protection Program from the Small Business Administration, the $3.6 million non-cash gain on sale of properties due to the write off of related asset retirement obligations and the recognition of $2.0 million of CO2 and plant income related to the acquired Vacuum properties partially offset by the $0.6 million write off of certain assets.

Interest expense

Interest expense decreased $2.3 million, or 28%, from $8.2 million for the year ended December 31, 2020 to $5.9 million for the year ended December 31, 2021. The decrease is primarily attributable to decreased borrowings and a lower interest rate.

Liquidity and Capital Resources

Following the consummation of this offering, our primary sources of liquidity and capital will be cash flows generated by operating activities and borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility were $145.0 million at December 31, 2021 and $125.0 million at September 30, 2022, and the remaining availability under our Credit Facility was $20.0 million at December 31, 2021 and $40.0 million at September 30, 2022. Additionally, we had positive net working capital (including cash and excluding the effects of derivative instruments) of $17.6 million at December 31, 2021 and $19.8 million at September 30, 2022. After giving effect to this offering and the use of proceeds as described under “Use of Proceeds” as of September 30, 2022, we would have had $37 million outstanding, $128.0 million available under our Credit Facility (based on the outstanding balance on the Credit Facility subsequent to the offering and the borrowing base as of September 30, 2022) and $11.1 million of cash (based on our cash balance as of September 30, 2022), for total liquidity of $139.1 million.

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As a publicly traded partnership, our primary sources of liquidity and capital resources will be from cash flow generated by operating activities and borrowings under our Credit Facility. Historically, our primary sources of liquidity have also included capital contributions by our equity holders, but we do not expect to rely on management or our partners for capital following the completion of this offering. We may need to utilize the public equity or debt markets and bank financings to fund future acquisitions or capital expenditures, but the price at which our common units will trade could be diminished as a result of the limited voting rights of unitholders. We expect to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. We expect to repay any debt incurred by us to complete such acquisitions in order to meet our long-term goal of remaining substantially debt free. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to refinance our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero.

In addition, our partnership agreement permits us to borrow funds to make distributions to our unitholders. We may, but are under no obligation to, borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. For example, we generally intend to hedge a portion of our production. We generally will be required to settle our commodity hedge derivatives within twenty-five days of the end of the month. As is typical in the oil and gas industry, we do not generally receive the proceeds from the sale of our hedged production until 20 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, we will be required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may borrow to fund our distributions.

Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions were $70.4 million for the nine months ended September 30, 2022 and $21.4 million for the nine months ended September 30, 2021. Our capital expenditures including acquisitions were $227.8 million for the year ended December 31, 2021 and $16.7 million for the year ended December 31, 2020.

We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. We were required under our Credit Facility to hedge at least 75% of reasonably anticipated projected production of proved developed producing reserves for the 12-month period following January 1, 2022. However, as of any time, if the net leverage ratio (the ratio of total net debt-to-EBITDAX) is less than or equal to 1.0 to 1.0 and availability under the Credit Facility is equal to or greater than 20% of the borrowing base then in effect, the minimum required hedge volume for month one through month 24 will be

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reduced to 50%. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. However, from September 30, 2022 through the next scheduled spring redetermination in March 2023, we received a waiver to reduce the hedging requirement from 30 months to 18 months beginning January 1, 2023 and from 50% to 45% of the reasonably anticipated projected production. See Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement” for more information. Our policy is to consider hedging a portion of our production at commodity prices management deems attractive.

Our budgets for drilling, completion and recompletion activities and facilities costs were approximately $30 million for 2022 and are approximately $30 million for 2023. We expect to allocate the majority of our 2023 budget to projects focused on enhancing existing production. For the nine months ended September 30, 2022, we made approximately $11.9 million of drilling, completion and recompletion expenditures. We expect to fund these capital expenditures from cash flow from operations.

The amount and timing of these capital expenditures is substantially within our control and subject to management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to the prevailing and anticipated prices for oil, NGLs and natural gas, the availability of necessary equipment, infrastructure and capital, seasonal conditions and drilling and acquisition costs. Any postponement or elimination of our development program could result in a reduction of proved reserve volumes, production and cash flow, including distributions to unitholders.

Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our distributions, meet our debt obligations and fund our 2023 capital development programs from cash flow from operations and the net proceeds of this offering.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or distributions to unitholders. Alternatively, we may fund these expenditures using borrowings under our Credit Facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us, finance the capital expenditures necessary to maintain our production or proved reserves, or make distributions to unitholders.

Cash flows

The following table summarizes our cash flows for the periods indicated (in thousands):


	For the Year Ended December 31,						For the Nine Months Ended September 30,
	2021			2020			2022			2021

Net cash provided by operating activities	$	73,726		$	18,964		$	103,668		$	47,000

Net cash used by investing activities		(227,801	)		(16,718	)		(70,443	)		(21,415	)

Net cash provided by (used in) financing activities		139,689			14,067			(29,624	)		(35,089	)

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Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Net cash provided by operating activities

Net cash provided by operating activities increased $56.7 million for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 due to a change in non-cash derivative loss of $133.7 million, changes in non-cash expenses of $3.2 million and decrease in forgiveness in debt of $9.2 million partially offset by decreased net income of $10.7 million, increased realized derivative losses of $70.2 million and changes in operating assets and liabilities of $8.5 million. Excluding the $133.7 million of noncash effects of derivative losses, net income would have increased $123.0 million primarily as a result of improved prices in 2022 compared to 2021 and increased production primarily due to the Vacuum and Andrews acquisitions in late 2021 partially offset by increased costs.

Net cash used by investing activities

Net cash used by investing activities increased $49.0 million for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 due to an increase in proved property acquisitions of $36.2 million, other property of $12.6 million and an increase in development costs of $0.2 million.

Net cash used by financing activities


	For the Nine Months Ended September 30,
	2022			2021
	(in thousands)

Proceeds from long-term debt	$	1,099,000		$	1,052,000

Payments on long-term debt	$	(1,119,000	)	$	(1,087,000	)

Debt issuance costs	$	(132	)	$	(89	)

Capitalized offering costs	$	(3,012	)	$	—

Distributions	$	(6,480	)	$	—


Net cash used in financing activities	$	(29,624	)	$	(35,089	)

Net cash used in financing activities decreased $5.5 million for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 due to a decrease in net repayments under our credit facility of $15.0 million partially offset by a $6.5 million increase in distributions and an increase in capitalized offering costs of $3.0 million.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Net cash provided by operating activities

Net cash provided by operating activities increased $54.8 million for the year ended December 31, 2021 compared to the year ended December 31, 2020 due to an increase in net income of $215.7 million partially offset by a decrease in non-cash expenses of $135.8 million, a change in non-cash derivative gain of $11.9 million, forgiveness of debt of $9.2 million, a decrease in non-cash incentive compensation of $1.8 million, changes in other non-cash items of $1.4 million and changes in operating assets and liabilities of $0.8 million. The improvement in net cash provided by

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operating activities is primarily related to improved prices in 2021 compared to 2020 and increased production as a result of owning the San Juan Basin properties for the entire year and the acquisition of the Vacuum properties in 2021 partially offset by increased costs.

Net cash used in investing activities

Net cash used in investing activities increased $211.1 million for the year ended December 31, 2021 compared to the year ended December 31, 2020 due to an increase in proved property acquisitions of $175.0 million, other property additions of $33.0 million and development costs of $3.4 million partially offset by a decrease in unproved property acquisitions of $0.3 million.

Net cash provided by (used in) financing activities


	For the Year Ended December 31,
	2021			2020
	(in thousands)

Proceeds from long-term debt	$	1,437,000		$	1,932,152

Payments on long-term debt	$	(1,427,000	)	$	(1,968,000	)

Proceeds from temporary equity investment	$	—		$	50,695

Proceeds from partners’ investment	$	132,660		$	—

Debt issuance costs	$	(2,832	)	$	(709	)

Payment on vesting of restricted units	$	—		$	(40	)

Distributions	$	(139	)	$	(31	)


Net cash provided by financing activities	$	139,689		$	14,067

Net cash provided by financing activities increased $125.6 million for the year ended December 31, 2021 compared to the year ended December 31, 2020 due to an increase in proceeds received from partners of $82.0 million and in net borrowings under our credit facility of $45.8 million partially offset by an increase in debt issuance costs of $2.1 million and distributions of $0.1 million.

Revolving credit agreement

On November 1, 2021, we entered into a new four-year, $165 million senior secured credit facility (the “Credit Facility”) with certain commercial banks. Our Credit Facility permits us to use proceeds for general partnership purposes including distributions to our unitholders. Our obligations under the Credit Facility are secured by all of our assets, including (i) our interest in Cross Timbers, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by us and our wholly-owned subsidiaries. The facility has a maturity date of November 1, 2025. We use the facility for general partnership purposes. In connection with entering into the Credit Facility, as of September 30, 2022, we incurred financing fees and expenses of approximately $2.8 million before accumulated amortization of $0.6 million. These costs are being amortized over the life of the Credit Facility. Such amortized expenses are recorded as interest expense on the statements of operations. As of September 30, 2022, we had $125 million in borrowings outstanding under our Credit Facility and $40 million in availability. After giving effect to this offering and the use of proceeds as described under “Use of Proceeds” as of September 30, 2022, we would have had $37 million outstanding and $128 million available under our Credit Facility, based on the outstanding balance on the Credit Facility subsequent to the offering and the borrowing base as of September 30, 2022.

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Under our Credit Facility, the borrowing base is determined based on the value of our oil and natural gas properties and the oil and gas properties of our wholly owned subsidiaries. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. As of November 3, 2022, the last date of redetermination, our borrowing base was $165 million.

Redetermination of the borrowing base under the Credit Facility is based primarily on reserve reports that reflect commodity prices at such time and occurs semi-annually, in March and September, as well as upon requested interim redeterminations by the lenders at their sole discretion. We also have the right to request additional borrowing base redeterminations each year at our discretion. Significant declines in commodity prices may result in a decrease in the borrowing base. These borrowing base declines can be offset by any commodity price hedges we enter. Our next borrowing base redetermination is scheduled for March 2023.

Our Credit Facility contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on merging or consolidating with another company, limitations on making certain restricted payments, limitations on investments, limitations on paying distributions on, redeeming, or repurchasing common units, limitations on entering into transactions with affiliates, and limitations on asset sales. The Credit Facility also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.

At our election, interest on borrowings under the Credit Facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The weighted average interest rate on Credit Facility borrowings was 4.00% in 2021. The effective borrowing rate under our Credit Facility was 6.4% as of September 30, 2022.

We are required to maintain (i) a current ratio (the ratio of current assets to current liabilities) greater than 1.0, which for purposes of this definition includes availability under the Credit Facility but excludes the fair value of derivative instruments, and (ii) a ratio of total net debt-to-EBITDAX of not greater than 3.00 to 1.00. For purposes of the total net debt-to-EBITDAX ratio, total net debt is total debt for borrowed money (including capital leases and purchase money debt) minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), and EBITDAX includes Cross Timber’s EBITDAX only to the extent of cash distributions received by us. For purposes of our Credit Facility, EBITDAX is defined to mean net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and any extraordinary or non-recurring charges, minus any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Furthermore, we only include realized hedge gains less realized hedge losses and the consolidated expenses of ours and our subsidiaries. We were in compliance with all financial and other covenants of the Credit Facility, except the covenant regarding hedge

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volumes required as of September 30, 2022. We received a waiver for this exception in September 2022. This waiver, which will continue through the next scheduled redetermination in March 2023, allows us to reduce the hedging requirement from 30 months to 18 months beginning January 1, 2023 and from 50% to 45% of the reasonably anticipated projected production. We believe that we have a sufficient combination of resources and operating flexibility to ensure that we remain in compliance with our debt covenants for at least the next 12 months.

Our Credit Facility permits us to make distributions of 100% of our “Distributable Cash Flow” so long as (i) at the time of any such distribution and immediately after giving effect thereto, no default, event of default or borrowing base deficiency has occurred and is continuing, (ii) the our ratio of total net debt-to-EBITDAX does not exceed 2.00 to 1.00 as of the last day of the fiscal quarter most recently ended for which our financial statements have been delivered (determined on a pro forma basis after giving effect to such distribution) and (iii) after giving effect to such distribution, there is at least 20% of total borrowings then available under our Credit Facility. For purposes of our Credit Facility, “Distributable Cash Flow” is defined, generally, to mean (a) our EBITDAX during each period of four consecutive quarters (a “rolling period”), minus the increase (or plus the decrease) in working capital from the previous rolling period minus (b) the sum of (i) capital expenditures paid in cash, (ii) cash interest expense, (iii) cash taxes paid, (iv) exploration expenses or costs paid in cash, (v) restricted payments made in cash (other than any prior distributions of Distributable Cash Flow) and (vi) to the extent not included in this clause (b) and otherwise added back in the calculation of EBITDAX, any other cash charge that reduces our earnings. The amount of Distributable Cash Flow with respect to any fiscal quarter is further reduced by all prior distributions of Distributable Cash Flow during the applicable rolling period.

Further, our Credit Facility requires us to hedge at most 90% of reasonably anticipated projected production and required us to hedge at least 75% of reasonably anticipated projected production of proved developed producing reserves for the 12-month period following January 1, 2022. See Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement” for more information. However, as of any time, if the net leverage ratio (the ratio of total net debt-to-EBITDAX) is less than or equal to 1.0 to 1.0 and availability under the Credit Facility is equal to or greater than 20% of the borrowing base then in effect, the minimum required hedge volume for month one through month 24 will be reduced to 50%; and the requirement to maintain a minimum required hedge volume for months 25 through month 30 shall be removed.

Contractual obligations and commitments

We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses.

Derivative contracts

We have entered into derivative instruments to hedge our exposure to commodity price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2021, the current liability related to such contracts was $6.5 million and the non-current liability was $0.1 million. Such payments will generally be funded by higher prices received from the sale of oil, NGLs and natural gas. For further information on derivative contracts, see Note 10 in the financial statements included elsewhere in this prospectus.

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Asset Retirement Obligation

At December 31, 2021, we had asset retirement obligations of $104.5 million inclusive of a current portion of $1.1 million. For further information on asset retirement obligations, see Note 8 in the financial statements included elsewhere in this prospectus.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Also, gains and losses on these instruments are generally offset by losses and gains on the offsetting expenses.

Commodity price risk

To reduce the impact of fluctuations in oil, NGL and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL and natural gas production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.

As of September 30, 2022, the fair market value of our oil, NGL and natural gas derivative contracts was a net liability of $54.4 million. Based upon our open commodity derivative positions at September 30, 2022, a hypothetical 10% change in the NYMEX WTI and Henry Hub prices, OPIS prices and basis prices would change our net oil, NGL and natural gas derivative liability by approximately $26.3 million.


(in thousands)	Fair Value at September 30, 2022			Hypothetical Price Increase or Decrease of 10%

Derivative asset (liability) – Crude Oil	$	(7,919	)	$	11,852

Derivative asset (liability) – Natural Gas	$	(43,560	)	$	12,794

Derivative asset (liability) – Natural Gas Liquids	$	(2,960	)	$	1,655


Net cash used in financing activities	$	(54,439	)	$	26,301

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The hypothetical change in fair value could be a gain or loss depending on whether prices increase or decrease. Please see “—Derivative Arrangements.”

Counterparty and customer credit risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds in major financial institutions. We often have balances in excess of the federally

insured limits.

We sell oil, NGL and natural gas production to various types of customers. Credit is extended based on an evaluation of the customer’s financial condition and historical payment record. The future availability of a ready market for our production depends on numerous factors outside of our control, none of which can be predicted with certainty. For the year ended December 31, 2021, we had three customers that each accounted for more than 10% of total revenues. See “Business—Operations—Marketing and Customers.” We do not believe the loss of any single purchaser would materially impact our operating results because oil, NGLs and natural gas are fungible products with well-established markets and numerous purchasers.

At December 31, 2021, we had commodity derivative contracts with counterparties. We are currently not required to provide collateral or other security to counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, we use master netting arrangements to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review.

Interest rate risk

At September 30, 2022, we had $125.0 million of variable rate debt outstanding. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $1.3 million per year. See “—Liquidity and Capital Resources—Revolving credit agreement.”

Critical accounting policies and estimates

Our financial position and results of operations are significantly affected by accounting policies and estimates related to our oil and gas properties, proved reserves, asset retirement obligation and commodity prices and risk management, as summarized below. See Note 1 of the notes to the audited financial statements included elsewhere in this prospectus for an expanded discussion of our significant accounting policies and estimates made by management.

Property and equipment

A majority of the property costs reflected in the accompanying balance sheet are from the acquisition of proved properties. Successful drill well costs are transferred to proved properties generally within one month of the well completion date.

Depreciation, depletion and amortization (DD&A) of proved producing properties is computed on the unit-of- production method based on estimated proved oil and gas reserves. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.

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The impairment assessment process is primarily dependent upon the estimate of proved reserves. Any overstatement of estimated proved reserve quantities would result in an overstatement of estimated future net cash flows, which could result in an understated assessment of impairment. The subjectivity and risks associated with estimating proved reserves are discussed under “Oil and Natural Gas Reserves” below. Prediction of product prices is subjective since prices are largely dependent upon supply and demand resulting from global and national conditions generally beyond our control. However, management’s assessment of product prices for purposes of impairment is consistent with that used in its business plans and investment decisions. While there is judgment involved in management’s estimate of future product prices, the potential impact on impairment has not been significant recently since product prices have been substantially higher than our net acquisition and development costs per Boe. However, due to the significant decline in product prices as a result of the COVID-19 pandemic, we recognized a $134.1 million impairment on certain of our proved properties in 2020. Prior to 2020, our historical impairment of proved properties included $177.4 million of proved property impairments from 2014 through 2018. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impracticable to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.

Costs of retired, exchanged, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently.

Oil and natural gas reserves

Our proved oil and natural gas reserves are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluation and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production, subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using the 12-month average prices, estimated reserve quantities can be significantly impacted by changes in product prices.

Proved reserves, as defined by the Financial Accounting Standards Board (“FASB”) and adopted by the SEC, are limited to known reservoirs that indicate economic producibility through actual production or conclusive formation tests, and generally cannot extend beyond the immediate adjoining undrilled portion.

DD&A of producing properties is computed on the unit-of-production method based on estimated proved oil and natural gas reserves. While total DD&A expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in timing of when

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DD&A expense is recognized. Downward revisions of proved reserves result in an acceleration of DD&A expense, while upward revisions tend to lower the rate of DD&A expense recognition. During 2021, net upward revisions to proved reserves on a Boe basis occurred, which will result in a decrease in DD&A expense of 49% in 2022.

The standardized measure of discounted future net cash flows and changes in such cash flows, are prepared using assumptions required by FASB and the SEC. Such assumptions include 12-month average oil and natural gas prices, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent management’s estimated current market value of proved reserves.

Derivatives

We use derivatives to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. We record all derivatives on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date.

We do not designate these derivative contracts as cash flow hedges. Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil, NGL and natural gas revenues. Settlements of derivatives are included in cash flows from operating activities.

While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under GAAP, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements.

See also “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk”, for the effect of price changes on derivative fair value gains and losses.

Asset retirement obligations

If the fair value for an asset retirement obligation can be reasonably estimated, the liability is recognized in the period when it is incurred. Oil and natural gas producing companies incur this liability upon acquiring or drilling a well. The retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to proved properties on the balance sheet. Periodic accretion of the discount of the estimated liability is recorded as an expense in the income statement.

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in

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prospective changes to DD&A expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Revenue recognition and gas balancing

Oil, NGL and natural gas revenues are recognized upon the satisfaction of the performance obligation which occurs at the point in time when control of the product transfers to a customer, in an amount that reflects the consideration to which we expect to be entitled in exchange for the product.

Recent accounting pronouncements

A summary of recent accounting pronouncements and our assessment of any expected impact of these pronouncements if known is included in Note 1 to the audited consolidated financial statements included elsewhere in this prospectus.

Internal controls and procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes- Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report to be filed with the SEC. We have elected to avail ourselves of the provision of the JOBS Act that permits emerging growth companies to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act.

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BUSINESS AND PROPERTIES

Business Overview

We seek to maintain a flat to low growth production profile through a combination of low-risk development and exploitation of our existing properties, generally funded by cash flow from operating activities, and future acquisitions of producing properties. We believe this will allow us to increase our reserves and production and, over time, to increase distributions to our unitholders. To date we have been successful in offsetting the natural decline in production from reservoir depletion through acquisitions and drilling. Historically, funding sources for our capital expenditures, including acquisitions, have included proceeds from bank borrowings, cash from our partners and cash flow from operating activities. Following this offering, we expect to continue to fund our capital expenditures primarily with cash flow generated by operating activities, but may use borrowings under our Credit Facility in connection with acquisitions in particular. Additionally, we may seek to issue additional equity securities from time to time as market conditions allow to facilitate future acquisitions. Our development budget is approximately $30.0 million for 2023.

The members of our management team have an average of 32 years’ experience in the oil and gas industry and previously held executive roles at XTO. Our management team has successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets for more than 30 years, completing hundreds of acquisitions totaling over $15 billion. Additionally, our Chief Executive Officer, Bob Simpson, has a greater than 45-year history in the oil and gas industry. Mr. Simpson founded Cross Timbers Oil company in 1986 (subsequently named XTO Energy) and served as Chief Executive Officer and Chairman over the life of the company, culminating with a sale to Exxon Corporation for $41 billion in 2010. Additionally our management team has collectively invested more than $500 million in us since our inception. We believe our management team has the experience, expertise and commitment to create significant value for our unitholders in the form of cash distributions combined with growth in revenues and production. Certain members of our existing

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management team were acting or former officers of Southland when it voluntarily filed for Chapter 11 bankruptcy protection on January 27, 2020. Please see “Management—Southland Bankruptcy” for more information.


	Estimated Proved Reserves as of July 31, 2022⁽¹⁾
	SEC Pricing Proved Developed Reserves (MBoe)⁽²⁾		SEC Pricing Proved Reserves (MBoe)		NYMEX Pricing Proved Developed Reserves (MBoe)⁽³⁾		NYMEX Pricing Proved Reserves (MBoe)⁽³⁾

Permian Basin		39,244.6		61,643.5		37,444.0		59,722.1

San Juan Basin		72,601.3		72,601.3		68,818.0		68,818.0

Other⁽⁴⁾		5,423.8		8,803.0		5,128.4		8,507.6


Total		117,269.7		143,047.8		111,390.4		137,047.7

(1)	Presented on an oil-equivalent basis using a conversion of six thousand cubic feet of natural gas to one stock tank barrel of oil. This conversion is based on energy equivalence and not on price or value equivalence.

(2)	SEC pricing, as required by the rules and regulations of the SEC, is the unweighted arithmetic average of the first-day-of-the-month price for each month within such period using published benchmark oil and gas prices, unless prices are defined by contractual arrangements.”

(3)

(4)	Other includes reserves in various other locations in the United States, primarily in Utah and Mississippi.

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	Estimated PV-10 as of July 31, 2022⁽⁴⁾
(in millions)	SEC Pricing Proved Developed PV-10⁽¹⁾⁽²⁾		SEC Pricing Proved PV-10⁽¹⁾		NYMEX Pricing Proved Developed PV-10⁽³⁾		NYMEX Pricing Proved PV-10⁽³⁾

Permian Basin	$	826.4	$	1,272.2	$	659.2	$	992.9

San Juan Basin	$	464.7	$	464.7	$	400.8	$	400.8

Other⁽⁵⁾	$	55.3	$	81.3	$	48.4	$	67.6


Total	$	1,346.4	$	1,818.2	$	1,108.4	$	1,461.3

(1)	Presented on an oil-equivalent basis using a conversion of six thousand cubic feet of natural gas to one stock tank barrel of oil. This conversion is based on energy equivalence and not on price or value equivalence.

(2)	SEC pricing, as required by the rules and regulations of the SEC, is the unweighted arithmetic average of the first-day-of-the-month price for each month within such period using published benchmark oil and gas prices, unless prices are defined by contractual arrangements.”

(3)

(4)

(5)	Other includes reserves in various other locations in the United States, primarily in Utah and Mississippi.

The following table summarizes information regarding our active well count and development locations included in our reserve report as of July 31, 2022.


	As of July 31, 2022
	Active Oil and Natural Gas Wells				Active CO₂ Injection Wells				Conventional PUD Locations⁽¹⁾				Recomplete Locations⁽²⁾				Workover Locations⁽³⁾
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net

Permian Basin		3,912		685.3		55		39.1		233		108.7		51		32.8		23		22.6

San Juan Basin		11,509		1,093.8		—		—		—		—		—		—		—		—

Other⁽⁴⁾		3,025		88.4		—		—		4		1.8		—		—		—		—


Total		18,446		1,867.5		55		39.1		237		110.5		51		32.8		23		22.6

(1)	Approximately 97% of our wells are drilled conventionally. However, from time to time a small number of wells are horizontally completed.

(2)	Well locations we believe we can recomplete into another producing zone or zones.

(3)	Well locations where we believe a currently completed zone can be improved or restored by performing remedial workovers.

(4)	Other includes properties in various other locations in the United States, primarily in Utah and Mississippi.

Our Properties

Permian Basin

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plant in the Permian Basin of New Mexico for approximately $52.6 million (the “Additional Interest Vacuum Acquisition”). As of September 30, 2022, we had 55 (gross) active CO₂ injection wells. Production from our CO₂ wells was 16.3 MMcf/d during the first nine months of 2022.

The Permian Basin is one of the oldest and most prolific producing basins in North America, with proven reserves of over 12.1 billion barrels of oil and 49.9 trillion cubic feet of natural gas as of 2019 according to the U.S. Energy Information Administration (“EIA”). Consisting of approximately 75,000 square miles centered around Midland, Texas, the Permian spans across west Texas and southeast New Mexico. The Permian Basin has been a significant source of oil production in the United States since the 1920s and, according to the EIA, accounted for approximately 41% of all oil production and approximately 15% of all natural gas production in the United States as of December 31, 2021. As of December 31, 2022, 350 rigs were running in the Permian, representing 46% of all land rigs running in the United States according to Baker Hughes rig count data. While horizontal development is the primary focus for many operators, there continues to be significant conventional oil and gas drilling throughout the Permian Basin. Through enhanced oil recovery methods such as CO₂injection, operators like us are able to unlock incremental additional hydrocarbon production in these older, conventional assets at comparatively lower costs as compared to the drilling and completion costs of horizontal wells.

Our management team believes the development and exploitation of conventional assets in the Permian Basin is among the most economic oil and natural gas plays in the United States. Since completing the 2021 Acquisitions, we have focused our efforts on returning wells to production as well as on other low-risk maintenance projects. As we gain a greater understanding of these recently acquired assets, we expect to increase our drilling and recompletion work. Substantially all of our acreage in the Permian Basin is held by production, which means we do not have to drill any wells to maintain ownership of our leases. We drilled or participated in the drilling of approximately 6 gross wells in the Permian Basin during 2022. Based on current commodity prices, we expect to drill or participate in the drilling of approximately 12 gross wells in 2023. We recompleted 13 gross wells in the Permian Basin in 2022 and expect to recomplete approximately 14 gross wells in 2023. We returned 12 gross wells to production in the Permian Basin in 2022 and expect to return 9 gross wells in 2023. Our decline rate for our Permian Basin properties over the next 12 months is currently estimated to be approximately 7%.

San Juan Basin

We acquired our initial 175,376 gross leasehold and mineral acres in the San Juan Basin in 2012 and 2013. We subsequently acquired 273,187 additional gross leasehold and mineral acres in June 2020.

The San Juan Basin covers approximately 7,500 square miles in northwestern New Mexico, southwestern Colorado, and parts of Utah and Arizona. Primarily producing natural gas, the San Juan Basin has multiple different formation targets including conventional and unconventional tight sands, coalbed methane and shale. The San Juan is one of the oldest producing basins in the United States, with the first conventional natural gas well was drilled in 1921. With the discovery and development of coalbed methane reserves, the San Juan Basin was one of the most prolific natural gas basins in the United States in the 1980s and 1990s. Development activity within the San Juan Basin continued at a significant pace until 2008. With the collapse of commodity prices in 2007, development activity dropped to a very low rate, falling from approximately 40 drilling rigs into 2007 to less than five rigs by 2012. More recently, however, activity within the San Juan Basin has picked up through continued exploration of the unconventional Mancos Shale play. In 2016, the United States Geological Survey (“USGS”) estimated that there were 66.3 trillion cubic feet of recoverable natural gas in the Mancos Shale, which is a forty-fold increase from the 1.6 trillion cubic feet of recoverable natural gas estimated by USGS in 2003.

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We drilled or participated in the drilling of approximately 18 gross wells in the San Juan Basin during 2022. Based on current commodity prices, we expect to drill or participate in the drilling of approximately 22 gross wells in 2023. We do not expect to recomplete any wells in the San Juan Basin in 2022 and 2023. We returned 5 gross wells to production in the San Juan Basin in 2022 and expect to return none in 2023.

Development Plan and Capital Budget

We expect to allocate the majority of our 2023 budget to projects focused on enhancing existing production. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2023 capital development programs from cash flow from operations and the net proceeds of this offering. We increased our 2021 capital program to $8.1 million compared to $5.5 million in 2020, primarily in response to the improved oil price environment and the improving global and national economic environment.

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Our Business Strategies

Our primary business objective is to make increasing distributions to our unitholders over time. To achieve our objective, we intend to execute the following business strategies:

•

Our Strengths

We believe that the following strengths will allow us to successfully execute our business strategies:

•

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32 years’ experience in the oil and gas industry and have previously held executive roles at XTO. Our management team has successfully executed on a strategy of acquiring and exploiting long-lived and low decline assets for more than 30 years. Members of our management team have collectively personally invested more than $500 million in us since our inception.

•

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Oil, Natural Gas and NGL Data

Reserves

Summary of Oil, Natural Gas and NGL Reserves. The following table presents our estimated net proved oil, natural gas and NGL reserves as of July 31, 2022 and December 31, 2021. The reserve estimates presented in the table below are based on reports prepared by Cawley, Gillespie & Associates, our independent petroleum engineers, which reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting, except that the column which provides our reserves at NYMEX Pricing uses pricing based on NYMEX futures prices. Our reserve data as of July 31, 2022 include the properties acquired as part of the Additional Interest Vacuum Acquisition described elsewhere in this prospectus.


	TXO Energy Partners
			As of July 31, 2022
	As of December 31, 2021 SEC Pricing(1)		SEC Pricing(1)		NYMEX Pricing(3)
Proved Reserves:

Oil (MBbls)		48,605.6		54,702.9		52,999.2

NGLs (MBbls)		18,027.6		20,905.6		19,820.9

Natural gas (MMcf)		379,275.9		404,635.8		385,365.8

Total Proved Reserves (MBoe)		129,845.9		143,047.8		137,047.7

Standardized Measure (in millions)	$	986.6		—		—

PV-10 (in millions)(2)	$	1,022.2	$	1,818.2	$	1,461.3

Proved Developed Reserves:

Oil (MBbls)		30,207.9		34,336.1		32,737.1

NGLs (MBbls)		17,434.2		19,638.9		18,566.3

Natural gas (MMcf)		353,214.9		379,768.1		360,522.5

Total Proved Developed Reserves (MBoe)		106,511.3		117,269.7		111,390.4

PV-10 (in millions)(2)	$	772.2	$	1,346.4	$	1,108.4

Proved Undeveloped Reserves:

Oil (MBbls)		18,397.7		20,366.8		20,262.1

NGLs (MBbls)		593.4		1,266.7		1,254.6

Natural gas (MMcf)		26,061.0		24,867.7		24,843.3

Total Proved Undeveloped Reserves (MBoe)		23,334.6		25,778.1		25,657.3

PV-10 (in millions)(2)	$	250.0	$	471.8	$	352.9

(1)

(2)

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from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of either well abandonment costs or income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

(3)


	2022		2023		2024		2025		2026		Thereafter

Natural gas price (per MMBtu)	$	8.36	$	5.63	$	4.66	$	4.50	$	4.40	$	4.40

Oil price (per Bbl)	$	94.92	$	86.49	$	79.38	$	74.64	$	71.02	$	71.02

(4)

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

Additional information regarding our proved reserves and estimated future cash flows therefrom can be found in the notes to our financial statements included elsewhere in this prospectus and in the reserve reports prepared by Cawley, Gillespie & Associates that are filed as exhibits to the registration statement of which this prospectus forms a part.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2021 and July 31, 2022 included in this prospectus are based on evaluations prepared by the independent petroleum engineering firm of Cawley, Gillespie & Associates in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC, except that the columns which provide our reserves at NYMEX Pricing use pricing based on NYMEX futures prices. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.

Under SEC rules, proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain, regardless of whether

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deterministic or probabilistic methods are used for estimation. If deterministic methods are used, the term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. If probabilistic methods are used, there should at least be a 90% probability that the quantities actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. Our independent reserve engineers use this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and estimated ultimate recoveries (“EURs”) per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy). All of our proved undeveloped reserves as of December 31, 2021 and July 31, 2022, relate to locations that are one offset away from an existing well.

Internal Controls

Our internal staff of petroleum engineers and geoscience professionals work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their preparation of reserve estimates. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” for more information. The reserves engineering group is responsible for the internal review of reserve estimates and includes Brandon Hudson, our Manager—Reservoir Engineering. The Reservoir Engineering Manager is primarily responsible for overseeing the preparation of our reserve estimates and has more than 15 years of experience as a reserve engineer. The reserves engineering group is independent of any of our operating areas. The Reservoir Engineering Manager is directly responsible for overseeing the reserves engineering group. The reserves engineering group reviews the estimates with our third-party petroleum consultants, Cawley, Gillespie & Associates, an independent petroleum engineering firm.

Cawley, Gillespie & Associates is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. The lead evaluator that prepared the reserve report was W. Todd Brooker, P.E., President at Cawley Gillespie. Mr. Brooker has been a Petroleum Consultant at Cawley, Gillespie & Associates since 1992 and became President in 2017. He graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. Mr. Brooker is a State of Texas Licensed Professional Engineer (License #83462) and a member of the Society of Petroleum Evaluation Engineers (SPEE) and the Society of Petroleum Engineers (SPE). Mr. Brooker meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; Mr. Brooker is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

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Proved Undeveloped Reserves (PUDs)

As of December 31, 2021, our proved undeveloped reserves were composed of 18,397.7 MBbls of oil, and 593.4 MBbls of NGLs and 26,061.0 MMcf of natural gas for a total of 23,334.6 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in PUDs, for the year ended December 31, 2021 (in MBoe):



Balance, December 31, 2020	13,946.4

Purchases of reserves	9,089.5

Revisions of previous estimates	309.1

Transfers to proved developed	(10.4	)


Balance, December 31, 2021	23,334.6

Revisions of previous estimates of 309.1 MBoe during the year ended December 31, 2021 resulted primarily from higher commodity prices (347 MBoe) partially offset by forecast changes (38 MBoe).

We converted 10.4 MBoe of any proved undeveloped reserves into proved developed reserves in 2021. Costs incurred relating to the development of oil and natural gas reserves were $8.1 million during the year ended December 31, 2021.

We drilled or participated in the drilling of 4 gross wells in the Permian Basin during 2021. We drilled or participated in the drilling of approximately 6 gross wells in the Permian Basin during 2022, and we expect to drill or participate in the drilling of approximately 12 gross wells in the Permian Basin during 2023. In addition, we participated in the drilling of 6 gross wells in the San Juan Basin during 2021. We drilled or participated in the drilling of approximately 18 gross wells in the San Juan Basin during 2022, and we expect to drill or participate in the drilling of approximately 22 gross wells in the San Juan Basin during 2023.

All of our PUD drilling locations are scheduled to be drilled within five years of December 31, 2021. We drilled and completed or participated in the drilling and completion of approximately 3 PUD locations during 2022 We anticipate drilling and completing or participating in the drilling and completion of approximately 51 PUD locations during 2023, 48 during 2024, 59 during 2025 and 57 during 2026. These PUD locations relate to 23.3 MMBoe of PUD reserves. Our development costs relating to the development of our PUDs at December 31, 2021 were expected to be approximately $13.5 million in 2022, and are projected to be $34.9 million in 2023, $39.1 million in 2024, $28.6 million in 2025 and $23.6 million in 2026 for a total of $139.7 million of future development costs. All of these PUD drilling locations are part of a development plan adopted by management. We expect that the substantial cash flow generated by our existing wells, in addition to availability under our Credit Agreement and the proceeds of this offering, will be sufficient to fund our drilling program, maintenance capital expenditures and PUD conversion into proved developed reserves in accordance with our development schedule. Please see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

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Natural Gas, Oil and NGL Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding our production and operating data for the periods indicated.

Production data:

Sales:


	Year Ended December 31,				Nine Months Ended September 30,
	2020		2021		2021		2022

Permian Basin

Natural gas sales (MMcf)		635		507		305		581

Natural gas liquids sales (MBbl)		77		81		43		246

Oil and condensate sales (MBbl)		897		985		600		1,581

Total (MBoe)		1,080		1,150		694		1,923

Total (MBoe per day)		3		3		2		7

San Juan

Natural gas sales (MMcf)		18,415		26,796		19,604		19,759

Natural gas liquids sales (MBbl)		772		995		745		740

Oil and condensate sales (MBbl)		34		35		22		19

Total (MBoe)		3,875		5,496		4,034		4,052

Total (MBoe per day)		11		15		15		15

Other

Natural gas sales (MMcf)		3,081		3,287		2,532		2,182

Natural gas liquids sales (MBbl)		11		13		10		7

Oil and condensate sales (MBbl)		9		13		11		5

Total (MBoe)		534		574		443		376

Total (MBoe per day)		1		2		2		1


Total (MBoe)		5,489		7,220		5,171		6,351

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Average realized sales prices:


	Year Ended December 31,				Nine Months Ended September 30,
	2020		2021		2021		2022

Permian Basin

Natural gas excluding effects of derivatives (per Mcf)	$	1.27	$	3.94	$	3.18	$	6.06

Natural gas liquids excluding effects of derivatives (per Bbl)	$	12.62	$	32.50	$	26.19	$	52.09

Oil and condensate excluding effects of derivatives (per Bbl)	$	37.30	$	67.93	$	63.73	$	98.46

San Juan

Natural gas excluding effects of derivatives (per Mcf)	$	1.90	$	4.03	$	3.64	$	6.33

Natural gas liquids excluding effects of derivatives (per Bbl)	$	9.78	$	24.59	$	22.48	$	33.25

Oil and condensate excluding effects of derivatives (per Bbl)	$	31.69	$	55.73	$	52.95	$	84.05

Other

Natural gas excluding effects of derivatives (per Mcf)	$	2.01	$	3.76	$	3.32	$	6.31

Natural gas liquids excluding effects of derivatives (per Bbl)	$	12.01	$	23.26	$	20.70	$	34.64

Oil and condensate excluding effects of derivatives (per Bbl)	$	38.75	$	59.30	$	58.89	$	93.22


($ / Boe)	$	15.57	$	30.38	$	26.87	$	53.17

Expense per Boe:


	Year Ended December 31,				Nine Months Ended September 30,
	2020		2021		2021		2022

Permian Basin

Production	$	25.23	$	30.67	$	31.44	$	33.89

Taxes, transportation, and other	$	3.95	$	6.90	$	5.36	$	11.63

Depreciation, depletion, and amortization	$	25.20	$	19.77	$	21.96	$	11.84

San Juan

Production	$	4.82	$	5.62	$	5.40	$	6.42

Taxes, transportation, and other	$	5.40	$	8.66	$	8.05	$	12.06

Depreciation, depletion, and amortization	$	1.97	$	2.03	$	2.06	$	1.18

Other

Production	$	6.02	$	5.39	$	5.03	$	7.33

Taxes, transportation, and other	$	4.31	$	4.33	$	3.96	$	4.67

Depreciation, depletion, and amortization	$	14.02	$	10.42	$	10.14	$	7.40

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Productive Wells

As of July 31, 2022, we owned interests in the following number of productive wells:


	Oil Wells		Gas Wells		Total

Permian Basin

Gross		3,786.0		126.0		3,912.0

Net		672.8		12.5		685.3

San Juan

Gross		30.0		11,479.0		11,509.0

Net		—		1093.8		1093.8

Other

Gross		735.0		2,290.0		3,025.0

Net		—		88.4		88.4

Total

Gross		4,551.0		13,895.0		18,446.0

Net		672.8		1,194.7		1867.5

Developed and Undeveloped Acreage

The following table sets forth information as of July 31, 2022 relating to our developed and undeveloped acreage. Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.


	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net

Permian Basin		140,998		76,755		160		80		141,158		76,835

San Juan Basin		445,271		245,545		3,292		2,496		448,563		248,041

Other		260,288		48,250		—		—		260,288		48,250


Total		846,557		370,550		3,452		2,576		850,009		373,126

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Drilling Results

The following table sets forth the results of our drilling activity for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.


	Years Ended December 31,
	2020				2021
	Gross		Net		Gross		Net

Development wells:

Completed as:

Gas wells		—		—		4		0.9

Oil wells		4		0.3		6		0.6

Non-productive		—		—		—		—


Total		4		0.3		10		1.5


Exploratory wells:

Completed as:

Gas wells		—		—		—		—

Oil wells		—		—		—		—

Non-productive		—		—		—		—


Total		—		—		—		—


Total		4		0.3		10		1.5

(1)	These four wells include two gross (0.0 net) wells drilled by other operators during the year ended December 31, 2020 in which we elected not to participate.

(2)	These 10 wells include two gross (0.0 net) wells drilled by other operators during the year ended December 31, 2021 in which we elected not to participate.

The following table sets forth information regarding our drilling activities as of September 30, 2022 and December 31, 2021, including with respect to wells awaiting completion, undergoing completion activities and which we have begun drilling subsequent to September 30, 2022.


September 30, 2022	Permian Basin				San Juan Basin
	Gross		Net		Gross		Net

Drilling		1		0.5		4		2.0

Awaiting completion		3		0.5		4		1.0

Undergoing completion activities		—		—		—		—

Drilling begun subsequent to September 30, 2022		3		2.0		3		1.5

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December 31, 2021	Permian Basin				San Juan Basin
	Gross		Net		Gross		Net

Drilling		—		—		—		—

Awaiting completion		4		1.3		—		—

Undergoing completion activities		—		—		—		—

We have completed 11 gross oil (0.6 net) wells and four gross gas (0.1 net) wells during the nine months ended September 30, 2022.

Operations

General

We operated wells responsible for approximately 66% of our production for the year ended December 31, 2020 and 68% for the year ended December 31, 2021. As operator, we design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities on a day-to-day basis. We do not own the drilling rigs or other oil field services equipment used for drilling or maintenance on the properties we operate.

Independent contractors engaged by us provide a portion of the equipment and personnel associated with these activities. We currently engage independent contractors who are engineers and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Virtually all of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies. Maverick Natural Resources Corporation, Occidental Petroleum Corporation and Jo Mill Oil Company are the operators on more than 50% of our non-operated acreage in the Permian Basin.

Our assets include a 50% interest in Cross Timbers Energy. The XTO Entities collectively own the remaining 50% interest in Cross Timbers. We account for our undivided interest in our investment in Cross Timbers using the proportionate consolidation method, pursuant to which we consolidate our proportionate share of assets (including reserves), liabilities, revenues and expenses of the joint venture. For the year ended December 31, 2021, Cross Timbers represents approximately 41% of our revenues and approximately 35% of our proved reserves, on a proportional ownership basis, with assets primarily located in the Permian Basin of Texas and New Mexico and the San Juan Basin of New Mexico and Colorado.

In accordance with the JV LLCA, Cross Timbers is managed by us and governed by a member management committee comprised of six members, three of whom are appointed by us and three of whom are appointed by the XTO Entities. The JV LLCA requires that certain matters, including certain material contracts or acquisitions, mergers, sale of substantially all assets or other change of control transactions, and transfers of our interest to a third party, be approved by unanimous consent of the voting members of the management committee and therefore require the approval of the XTO Entities. While Cross Timbers is required to distribute all net cash flow to the members pro rata in accordance with their respective membership interests on a quarterly basis pursuant to the JV LLCA, we do not have sole control of the amount of distributions to be made by Cross Timbers.

Cross Timbers is also a party to an operating and services agreement with us pursuant to which we provide all administrative services and conduct operations that are necessary or proper for the development, operation, protection and maintenance of the assets held by Cross Timbers in

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exchange for a management fee. We earned management fees from Cross Timbers of $4.4 million for the nine months ended September 30, 2022, $6.1 million for the year ended December 31, 2021, and $6.4 million for the year ended December 31, 2020.

Marketing and Customers

We market the majority of the natural gas, NGL, crude oil and condensate production from the properties on which we operate. We also market products produced by third party working interest owners who participate in various wells or production units on which we operate. We proportionately pay our royalty owners from the sales attributable to our working interest. Production from our properties is marketed using methods that are consistent with industry practice. Purchasers of our production are selected on the basis of price, credit quality and service reliability. Sales prices are negotiated based on factors normally considered in the industry, such as index or spot price, differentials based on the distance from tailgate of processing plants to end users, commodity quality and prevailing supply and demand conditions. Market volatility due to fluctuating weather conditions, international political developments, overall energy supply and demand, economic growth rates and other factors in the United States and worldwide have had, and will continue to have, a significant effect on energy prices.

We sell the majority of our production under arm’s length contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers, as is customary in our industry. We generally sell natural gas, NGL, crude oil and condensate production through production sale agreements with customary terms and conditions for the oil and natural gas industry at prevailing market prices, adjusted for quality, transportation fees, fractionation fees, regional price differentials, and, in the case of natural gas, energy content. Typically, our sales contracts are based on pricing provisions that are tied to a market index or postings. None of our contracts have minimum volume commitments. We have no commitments beyond twelve months to deliver a fixed or determinable quantity of our oil or natural gas production under our existing contracts.

For the year ended December 31, 2021, Phillips 66 Company, Tenaska Marketing and Eco-Energy, Inc. accounted for more than 40% of our total revenues, excluding the impact of our commodity derivatives. For the year ended December 31, 2020, Phillips 66 Company and Tenaska Marketing accounted for more than 40% of our total revenues, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our total revenue during such period. We generally do not have long-term contracts with our customers but rather we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, including on a combined basis, to a relatively small number of customers. The loss of any such purchaser could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any such purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers. For more details, see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—We depend upon several significant purchasers for the sale of most of our oil, natural gas and NGL production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.”

Hedging

Our policy is to hedge opportunistically a portion of our production at commodity prices management deems attractive to mitigate our exposure to lower commodity prices. Under our Credit

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Facility, we are allowed to hedge at most 90% of reasonably anticipated projected production, but we were required to hedge at least 75% of reasonably anticipated projected production of proved developed producing reserves for the 12-month period following January 1, 2022. From September 30, 2022 through the next scheduled redetermination in March 2023, we received a waiver to reduce the hedging requirement from 30 months to 18 months beginning January 1, 2023 and from 50% to 45% of the reasonably anticipated projected production. However, as of any time, if the net leverage ratio (the ratio of total net debt-to-EBITDAX) is less than or equal to 1.0 to 1.0 and availability under the Credit Facility is equal to or greater than 20% of the borrowing base then in effect, the minimum required hedge volume for month one through month 24 will be reduced to 50%. See Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement” for more information. While there is a risk that we may not be able to realize the benefits of rising prices, we enter into hedging agreements because of the benefits of predictable, stable cash flows.

We enter futures contracts, energy swaps, swaptions and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We also enter costless price collars, which set a ceiling and floor price to hedge our exposure to price fluctuations on natural gas sales. When actual commodity prices exceed the ceiling price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the floor price, we receive this difference from the counterparty. If the actual commodity price falls in between the ceiling and floor price, there is no cash settlement. For more details, see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—We use derivative instruments to economically hedge exposure to changes in commodity price and, as a result, are exposed to credit risk and market risk.”

For a more detailed discussion of our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk.”

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in producing oil and natural gas properties, particularly during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

There is also competition between oil and natural gas producers and other industries producing energy and fuel and alternative technologies to reduce energy and fuel consumption.

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Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the state and local jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Oil and Natural Gas Leases

The typical oil lease agreement covering our properties provides for the payment of royalties to the mineral owner for all hydrocarbons produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties range from less than 12.5% to 57.5%, resulting in a net revenue interest to us of 87.0% on average, on a 100% working interest basis. Based on the Standardized Measure, our value-weighted average net revenue interest on our properties was approximately 84.0%, on a 100% working interest basis, based on our December 31, 2021 reserve report. Substantially all of our leases are held by production and do not require continuous development.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a cursory review of the title to the properties in connection with the acquisition of producing wells and/or additional acreage. Typically, that examination is limited to the seller’s interest. At such time as we determine to conduct drilling operations, we administer a thorough title examination and perform curative work with respect to significant defects in title, prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects and/or other curative matters relative to those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on the most significant leases and, depending on the materiality of properties, we will review previously obtained title opinions, update title, and in most cases have new title opinions rendered by a licensed oil and gas attorney. Our oil and natural gas properties are subject to customary royalty and perhaps other interests, possible liens for current taxes and potentially other encumbrances which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we hold satisfactory title to all of our material assets. Although title to these properties is subject to certain encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights of way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

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Seasonality

Generally, but not always, the demand for oil and natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers also may impact this demand. In addition, pipelines, utilities, local distribution companies and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also impact the seasonality of demand. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

In addition, our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes or lighting storms, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. See “Risk Factors—Risks Related to the Oil, Natural Gas and NGL Industry and Our Business—Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.”

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs have not had a material adverse effect on our results of operations; however, we are unable to predict the future costs or impact considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Regulation Affecting Production

The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which we own or operate producing properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and natural gas we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Regulation Affecting Sales and Transportation of Commodities

Sales prices of oil, natural gas, condensate and NGLs are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil, natural gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting requirements.

The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of natural gas produced by us, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for natural gas production, if any, of the drilling program and the cost of such capacity. Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.

In addition to the regulation of natural gas pipeline transportation, FERC has jurisdiction over the purchase or sale of natural gas or the purchase or sale of transportation services subject to FERC’s jurisdiction pursuant to the EPAct 2005. Under the EPAct 2005, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the NGA to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act of 1978 up to $1,388,496 per violation per day. The anti-manipulation rule applies to activities of otherwise non jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No. 704 (defined below).

In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order

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No. 704, any market participant, including a producer that engages in certain wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to the formation of price indices. Not all types of natural gas sales are required to be reported on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 is intended to increase the transparency of the wholesale natural gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.

Through several issuances, FERC has signaled its intention of undertaking a “rigorous review” of reasonably foreseeable GHG emissions of new or expanded natural gas transportation facilities and their contribution to climate change, along with the enhanced consideration other factors such as project need, landowner impacts and environmental justice, in determining the benefits of a project and the significance of its environmental impacts. FERC considers project benefits and environmental impacts in determining whether to issue a certificate to construct a new project under the Natural Gas Act and in its environmental analysis required under the National Environmental Policy Act. On March 24, 2022, FERC announced that it was seeking comments on these draft proposed policies, which initially had been issued as guidance. If adopted, these policy changes may create delays in, and potentially affect the outcomes of, FERC’s future assessments of the need for and environmental impacts of gas pipeline projects in determining whether a project is required by the present or future public convenience or necessity under the Natural Gas Act, which in turn may reduce the development of interstate natural gas pipeline projects and the future availability of pipeline capacity to transport our natural gas production.

The FERC also regulates rates and terms and conditions of service on interstate transportation of liquids, including NGLs, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that certain interstate liquids pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 1, 2021, FERC established an annual index adjustment equal to the change in the producer price index for finished goods—0.21%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by obtaining market based rate authority (demonstrating the pipeline lacks market power), establishing rates by settlement with all existing shippers, or through a cost of service approach (if the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows for us.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of

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capacity or for new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

On February 17, 2022, FERC issued a Notice of Inquiry, seeking to explore oil pipeline capacity allocation issues that arise when anomalous conditions affect the demand for oil pipeline capacity and what actions FERC should consider to address those allocation issues. This proceeding was initiated in part by the impact of the COVID-19 pandemic on jet fuel shippers’ ability to access capacity on oil pipelines using historic-based prorationing. However, the Notice of Inquiry seeks comments on the broader issue of diminished access to oil pipeline capacity during anomalous conditions. Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.

In addition to FERC’s regulations, we are required to observe anti market manipulation laws with regard to our physical sales of energy commodities. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $1,323,791 per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of approximately $1,303,559 or triple the monetary gain to the person for each violation.

Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and the protection of the environment and natural resources (including threatened and endangered species and their habitat). Numerous governmental entities, including the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.

These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and on-going operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.

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These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Continued compliance with existing requirements is not expected to materially affect us. However, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.

In addition, governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political and regulatory risks in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has issued several executive orders focused on addressing climate change since taking office, including items that may impact the costs to produce, or demand for, oil and natural gas. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide. The Biden Administration is also considering revisions to the leasing and permitting programs for oil and natural gas development on federal lands.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Wastes

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our as well as the oil and natural gas exploration and production industry’s costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without

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regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own, lease, or operate numerous properties that have been used for oil, natural gas and NGL exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In 2015, the EPA and the U.S. Army Corps of Engineers (“Corps”) issued a final rule attempting to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”). The rule has the potential to expand CWA jurisdiction to ephemeral waters found in generally arid regions of the United States. In January 2020, the EPA and Corps replaced the WOTUS rule with the narrower Navigable Waters Protection Rule, and litigation ensued. In August 2021, a federal judge struck down the Navigable Waters Protection Rule. Soon after, the Biden administration and the Corps announced that they have stopped enforcing the Navigable Waters Protection Rule nationwide and that they are reverting back to the 1986 WOTUS definition. In November 2021, the EPA and Corps issued prepublication notice of a

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proposed rule to revise the definition of “waters of the United States” to put back into place the pre-2015 definition, updated to reflect consideration of Supreme Court decisions, including the Supreme Court’s April 2020 decision holding that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. In January 2022, the Supreme Court agreed to hear a case regarding the jurisdictional reach of WOTUS. In late December 2022, the EPA and the Corps issued a pre-publication final rule that, like the November 2021 proposed rule, utilizes the pre-2015 definition of WOTUS, with minor updates intended to account for recent decisions of the U.S. Supreme Court. In addition to the recently reopened litigation over the rule in district courts, multiple states and environmental groups have challenged the suspension of the rule, and future implementation of the WOTUS rule is uncertain at this time. To the extent any final rule expands the federal jurisdictional reach over WOTUS, we could be subject to additional permitting obligations, which could lead to potential project delays and additional compliance costs.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Subsurface Injections

In the course of our operations, we produce water in addition to oil, natural gas and NGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near belowground disposal wells used for the injection of natural gas related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies as well as the owners of underground injection wells. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil and natural gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.

Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards.

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These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Recently, there has been increased regulation with respect to air emissions resulting from the oil and natural gas sector. For example, the EPA promulgated rules in 2012 under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National Standards for Emission of Hazardous Air Pollutants program. With regard to production activities, these final rules require, among other things, the reduction of volatile organic compound (“VOC”) emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further requires that a subset of these selected wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.

The EPA has also imposed increasingly stringent performance standards on oil and gas operations. In 2016, the EPA issued regulations under NSPS OOOOa that require operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector. The proposed rule would establish standards of performance for sources that commence construction, modification or reconstruction after the date the proposed rule was published in the Federal Register and would establish emissions guidelines, which will inform state plans to establish standards for existing sources. The EPA issued a supplemental proposed rule in November 2022 to update, strengthen and expand its November 2021 proposed rule. The supplemental proposed rule would impose more stringent requirements on the natural gas and oil industry, and is expected to be finalized in 2023. State agencies have similarly imposed increasing restrictions on emissions from oil and gas operations. For example, in 2022, the New Mexico Environment Department adopted new regulations establishing emission reduction requirements for storage vessels, compressors, turbines, heaters, engines, dehydrators, pneumatic devices, produced water management units, and other equipment and processes. Increasingly stringent requirements on new oil and gas facilities, or the application of new requirements to existing facilities, could result in additional restrictions on operations and increased compliance costs, which could be significant.

The Bureau of Land Management (the “BLM”) also finalized rules (the “BLM methane rule”) in November 2016 that seek to limit methane emissions from exploration and production activities on federal lands by imposing limitations on venting and flaring of natural gas, as well as requirements for the implementation of leak detection and repair programs for certain processes and equipment. After attempts by the Trump administration to delay implementation of the BLM methane rule, and legal challenges both to the BLM methane rule and the delays, the BLM issued a final rule in September 2018 rescinding many of the provisions of the 2016 BLM methane rule, including the requirement to implement leak detection and repair programs, and imposing certain new requirements in a manner the BLM considered would reduce unnecessary compliance obligations on the industry. In July 2020 a federal district court in California vacated the 2018 rescission rule. BLM filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit; however, the federal district court in California entered a final judgment vacating the September 2018 rescission rule in October 2020. Separately, in October 2020, a federal district court judge in Wyoming vacated the 2016 rule. Environmental groups appealed the Wyoming decision in December 2020, and litigation is ongoing. In November 2022, the BLM issued a new proposed rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases.

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The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In addition, in October 2015, the EPA issued a final rule under the CAA, lowering the NAAQS for ground level ozone from the current standard of 75 ppb for the current 8 hour primary and secondary ozone standards to 70 ppb for both standards, and completed attainment/non-attainment designations in July 2018. EPA reviewed the 2015 standards in 2020, but retained the standard without revision. Impacts associated with the 2015 standard vary by geographic location, but could include additional fees and more stringent permitting requirements, among other things. None of the counties in which we operate have been designated as non-attainment.

Compliance with one or more of these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. In addition, our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions.

Regulation of GHG Emissions (Climate Change)

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large, GHG emission sources in the United States, including certain onshore and offshore oil and natural gas production sources, which include certain of our operations. As discussed above, federal regulatory action with respect to GHG emissions from the oil and natural gas sector has focused on methane emissions; however, implementation of the federal methane rules is uncertain at this time.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, the Inflation Reduction Act, recently passed by Congress and signed into law by President Biden, imposes several new climate-related requirements on oil and gas operators, including a first-ever fee on GHG emissions from certain facilities. The act also appropriates significant federal funding for renewable energy initiatives. These developments may make it harder for the oil and gas industry to attract capital. Additionally, the current administration has highlighted addressing climate change as a priority and has issued several executive orders addressing climate change, including one that calls for substantial action, such as the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. In the absence of comprehensive federal climate legislation, a number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although the United States

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had withdrawn from the Paris Agreement, President Biden has recommitted the United States and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the COP26, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector.

Although it is not possible at this time to predict how new laws or regulations in the United States that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. New laws or regulations may also negatively impact our competitive advantage; for example, the Inflation Reduction Act of 2022 includes a variety of tax credits to incentivize the development and use of solar, wind, and other alternative energy sources while imposing several new requirements on oil and gas operators. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time in multiple, though not all, potential scenarios. In addition, increasing social attention to ESG matters and climate change has resulted in demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products, encouraging the divestment of fossil fuel equities, and pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. For example, the Inflation Reduction Act of 2022 includes a variety of tax credits to incentivize development and use of solar, wind, and other alternative energy sources. Initiatives to incentivize a shift away from fossil fuels could reduce demand for hydrocarbons, thereby reducing demand for our services and causing a material adverse effect on our earnings, cash flows and financial condition.

Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas from dense subsurface rock formations. Hydraulic fracturing involves the

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injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. We engage in hydraulic fracturing as part of our operations currently and may continue to do so in the future.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, more recently, in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting and separately published in June 2016 an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under certain limited circumstances.” Also, the BLM finalized rules in March 2015, establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands. This rule was struck down by a Wyoming federal district court judge in June 2016 but was subsequently appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit. In September 2017, the Tenth Circuit issued a ruling to vacate this decision and dismiss the lawsuit challenging the rule in light of the BLM’s proposed rulemaking. In December 2017, BLM issued a final rule repealing the 2015 hydraulic fracturing rule. The BLM’s rescission of the rule was challenged by several environmental groups and states in the United States District Court for the Northern District of California. The United States District Court for the Northern District of California upheld the BLM’s rescission in a March 2020 decision.

From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Activities on Federal Lands

Oil and gas exploration, development and production activities on federal lands, including American Indian lands, are administered by the BLM. Operations on federal and tribal lands are frequently subject to permitting delays. Operations on these lands are also subject to NEPA. NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. We currently have exploration, development and production activities on federal lands and our proposed exploration, development and production activities are expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial.

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Moreover, the Biden administration’s January 2021 climate change executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands and in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices. In November 2021, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program,” which assessed the current state of oil and gas leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. In January 2022, a federal district court judge in Washington, D.C. vacated the results of the federal government’s Lease Sale 257, effectively canceling the sale, on the grounds that the federal government failed to consider foreign consumption of oil and natural gas from its GHG emissions analysis. In February 2022, a federal district court judge in Louisiana blocked the Biden Administration’s method of calculating the social costs associated with GHGs, and specifically blocked federal agencies from considering the findings from the White House Interagency Working Group, which had been tasked with devising new metrics based on the Obama-era calculations. In response, also in February 2022, the Biden administration asked the court to stay the injunction, and announced that it would be suspending or delaying new federal oil and gas leases. The Biden administration resumed its federal leasing program in April 2022. These recent developments and the Biden administration’s and certain federal courts’ focus on the climate change impacts of federal projects could result in significant changes to the federal oil and gas leasing program in the future. Restrictions surrounding onshore drilling, onshore federal lease availability, and restrictions on the ability to obtain required permits, could have a material adverse impact on our operators and, in turn, our operations.

Endangered Species and Migratory Birds Considerations

The federal Endangered Species Act (“ESA”), and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migrating birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of a 2011 settlement agreement, the U.S. Fish and Wildlife Service (“FWS”) was required to make a determination on listing numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The FWS missed the deadline and continues to review species for listing under the ESA. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. For example, the FWS issued a final rule in November 2022 listing two Distinct Population Segments (“DPS”) of the Lesser Prairie-Chicken. The listing, which will come into effect on January 24, 2023, lists the Southern DPS of the Lesser Prairie-Chicken as endangered, and the Northern DPS as threatened.

Similarly, if we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases. In August 2019, the FWS and the National Marine Fisheries Service issued three rules amending the implementation of the ESA regulations, among other things revising the process for listing species and designating critical habitat. Two more rules were finalized in 2020, which narrowed the definition of habitat and revised the criteria for designating and excluding critical habitat. A coalition of states and environmental groups has challenged the three 2019 rules. In November 2022, the U.S. District Court for the Northern District of California remanded (without vacatur) the 2019 rules to FWS for further review, with changes to

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the remanded rules planned for early 2023. The 2020 rules were rescinded in the summer of 2022. In addition, the federal government recently in the past has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. In December 2017, the Department of Interior issued a new opinion revoking its prior enforcement policy and concluded that an incidental take is not a violation of the Migratory Bird Treaty Act. In August 2020, a federal district court struck down the December 2017 opinion, and the Department of the Interior responded by issuing a new rule in January 2021 that reduced the activities that could incur liability under the MBTA. The Biden administration has since revoked the January 2021 rule; published an Advanced Notice of Proposed Rulemaking announcing an intent to solicit comments to help develop proposed regulations establishing a permitting system to authorize, under certain circumstances, the incidental take of migratory birds; and issued a Director’s Order “establishing criteria for the types of conduct that will be a priority for enforcement activities with respect to incidental take of migratory birds.”

OSHA

We are subject to the requirements of the OSHA and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. There can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Human Capital Resources

As of December 31, 2022, we had 191 total employees, 180 of which were full-time employees. From time to time we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements, and have not experienced any strikes or work stoppages. In general, we believe that employee relations are satisfactory.

We are focused on attracting, engaging, developing, retaining and rewarding top talent. We strive to enhance the economic and social well-being of our employees and the communities in which we operate. We are committed to providing a welcoming, inclusive environment for our workforce, with best-in-class training and career development opportunities to enable employees to thrive and achieve their career goals. The health, safety, and well-being of our employees is of the utmost importance.

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In response to COVID-19, we adopted enhanced safety measures and practices to protect employee health and safety and minimize the risk of business disruption.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition. Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of these other pending litigation matters, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

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MANAGEMENT

Management of TXO Energy Partners

We are managed and operated by our general partner, which is managed by the Board and executive officers of our general partner. The sole member of our general partner is controlled by the Founders. All of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to us as well as to its owners.

Upon the closing of this offering, we expect that our general partner will have seven directors, each of whom will be appointed by MSOG, as the sole member of our general partner. At least one of the directors will be independent as defined under the standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering. We will have at least two independent members of the audit committee by the date our common units first trade on the NYSE.

Our operations will be conducted through, and our assets will be owned by, various subsidiaries. However, we will not have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring personnel or by obtaining services of personnel employed by third parties, but we sometimes refer to these individuals, for drafting convenience only, in this prospectus as our employees because they provide services directly to us.

Following the consummation of this offering, neither our general partner nor the Founders will receive any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, benefits, bonus, long term incentives and other amounts paid to persons who perform services for us or on our behalf. Please read “Certain Relationships and Related Transactions.”

In evaluating director candidates, our general partner will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the Board to fulfill their duties.

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Executive Officers and Directors of Our General Partner

The following table sets forth certain information regarding the current executive officers and directors of our general partner upon consummation of this offering.


Name	Age		Position

Bob R. Simpson		74	Chief Executive Officer, Chairman and Director

Brent W. Clum		59	President of Business Operations and Chief Financial Officer, Director

Keith A. Hutton		64	President of Production and Development, Director

Scott T. Agosta		58	Chief Accounting Officer

Phillip R. Kevil		72	Director Nominee

Rick J. Settle		32	Director

J. Luther King, Jr.		82	Director

William (“Bill”) H. Adams III		64	Director Nominee

Bob R. Simpson—Chief Executive Officer, Chairman and Director. Bob R. Simpson founded MorningStar in June 2012 and has served as a Director and the Chairman of the Board of MorningStar since its founding and will serve as our Chief Executive Officer and Chairman. Mr. Simpson previously served as the Chairman and a Director of Southland from February 2015 until January 2020. Since August 2010 and until September of 2020, Mr. Simpson served as Co-Chairman of the Rangers Baseball Express and since September of 2020, he has served as Chair of the Executive Committee. He also served as Chief Executive Officer of XTO (a company he founded) until 2008 and as Chairman of XTO until 2010 when XTO merged with Exxon for $41 billion in one of the largest transactions in history for an independent oil and gas company. Mr. Simpson attended Baylor University, where he earned a B.B.A. in Accounting magna cum laude and then an M.B.A. He served in the Texas Army National Guard after graduation and then earned his certified public accountant (“CPA”) designation.

We believe that Mr. Simpson’s extensive industry background, leadership experience on private boards, and deep knowledge of our business make him well suited to serve as a member of our board of directors.

Brent W. Clum—President of Business Operations, Chief Financial Officer and Director. Brent W. Clum has served as our Chief Financial Officer since the founding of MorningStar in June 2012, and will serve as the President of Business Operations and Chief Financial Officer and a Director. He has also served as Director of MorningStar since October 2012. Mr. Clum served as Chief Financial Officer and Director of Southland from February 2015 until January 2020. Since August 2010, he has served as Chairman of the Finance and Audit Committee of Rangers Baseball Express. He served as Senior Vice President and Treasurer of XTO until the Exxon acquisition. Prior to joining XTO, Mr. Clum worked as a portfolio manager at Luther King Capital Management, served as a Managing Director at Invesco and was an Analyst for T. Rowe Price and Associates. He graduated from Baylor University with a Bachelors in Business Administration in Finance, Accounting and Marketing and from the Harvard Graduate School of Business with a Master’s in Business Administration. He is a CPA and a chartered financial analyst (“CFA”).

We believe that Mr. Clum’s industry experience, his previous leadership positions and finance-related roles, as well as his deep knowledge of our business make him well suited to serve as a member of our board of directors.

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Keith A. Hutton—President of Production and Development, Director. Keith A. Hutton will serve as our President of Production and Development and as a Director. He previously served as the Chief Executive Officer of MorningStar and has served as Director of MorningStar, in each case, since its founding in June 2012. Mr. Hutton served as Director of Southland from February 2015 until January 2020. Mr. Hutton also served as Chief Executive Officer and Director of XTO until the time of the Exxon acquisition. He remained a consultant with Exxon until January 2012. Mr. Hutton held various management positions for XTO over his 25 year career and was promoted to CEO in December 2008. Prior to joining XTO Energy in 1987, Mr. Hutton was employed with Sun Oil Company in both the international and domestic divisions for five years. He graduated from Texas A&M University with a B.S. in Petroleum Engineering and was named a Harold Vance Department of Petroleum Engineering Distinguished Graduate in 2009.

We believe that Mr. Hutton’s background in the energy industry and his experience as an executive make him well suited to serve as a member of our board of directors.

Scott T. Agosta—Chief Accounting Officer. Scott T. Agosta will serve as our Chief Accounting Officer. He has served as Chief Accounting Officer and Controller of MorningStar since its founding in June 2012. He also served as Chief Accounting Officer and Controller of Southland from August 2017 until January 2020. He served as Vice President—Financial Reporting of XTO from February 2005 until the Exxon acquisition in March 2012. Additionally, Mr. Agosta has served as a Board Member of the Junior Achievement of the Chisholm Trail since August 2009. Prior to joining XTO, Mr. Agosta worked as the Manager—Financial Reporting and Analysis at Devon Energy Corporation, served as Manager—Financial Reporting at Albemarle Corporation and was an Audit Manager at KPMG. He graduated from Louisiana State University with a B.B.A in Accounting. He is a CPA.

Phillip R. Kevil—Director Nominee. Phillip R. Kevil has been nominated to serve as a Director. He served as Director and as a member of the Audit Committee for XTO from 2004 until 2010. He also served as Vice President – Tax at XTO from 1987 until 1997. Mr. Kevil was responsible for all tax functions for Southland from 1975 until 1986. He graduated from the University of Texas at Arlington with a B.A in Accounting.

We believe that Mr. Kevil’s experience in corporate finance and the energy industry, as well has his previous experience as a director and audit committee member of a public company, make him well suited to serve as a member of our board of directors.

Rick J. Settle—Director. Rick J. Settle has served as a Director of MorningStar since July, 2020. Mr. Settle is a Principal at LKCM Headwater Investments, the private equity arm of Luther King Capital Management, and has previously served as a Vice President and Associate since joining the firm in October 2014. Prior to becoming a Principal at LKCM Headwater, Mr. Settle worked as a financial analyst for Citigroup. Mr. Settle also serves on the board of several privately-held companies including Kindthread, a healthcare apparel business, Aquila Environmental, an energy efficiency lighting ESCO, and Heart of Texas Propane, a retail propane distribution business. He graduated from the Texas Christian University with a B.B.A. in Finance, Entrepreneurial Management.

We believe that Mr. Settle’s deep knowledge of the energy industry and corporate finance make him well suited to serve as a member of our board of directors.

J. Luther King, Jr.—Director. J. Luther King, Jr. has served as Director of MorningStar since 2016. He served as Director of Tyler Technologies, Inc. (NYSE: TYL) from May 2004 until May 2021, serving on the Compensation and Audit Committees throughout his tenure at the company. Additionally, he has served as Director of LKCM Funds since February 1994. Mr. King also previously served as Director of Encore Energy Partners LP (Nasdaq: ENP) and as Director of XTO. Over the course of his career, he has served on the boards of several publicly traded companies,

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three of which were listed on the NYSE. In his position as a director of these companies, Mr. King has served as Chair of both Audit and Compensation committees. Mr. King currently serves as President of Luther King Capital Management, a position he has held since February 1979. He attended Texas Christian University, where he earned a B.S.C. and then an M.B.A. Mr. King is a CFA and was recognized by CFA Magazine as “Most Inspiring” in the Investment Advisory Profession in 2007. Additionally, Mr. King is a founding member of the Strategic Advisory Board of the CFA Society of Dallas/Fort Worth.

We believe that Mr. King’s experience serving on the boards of other public companies, along with his deep knowledge of our business and extensive industry experience, make him well suited to serve as a member of our board of directors.

William (“Bill”) H. Adams III—Director Nominee. Bill H. Adams has been nominated to serve as a Director. Mr. Adams currently serves as Director of Kimbell Royalty GP, LLC (NYSE: KRP), a position he has held since January 2017. In this position, Mr. Adams has served on the Audit, Compensation and Conflicts committees of the company. Mr. Adams served as Director of Double B Holdings, LLC from 2012 until 2021. Additionally, Mr. Adams has served as Director of Graham Savings Bank since 2018, of JBN Investments, LLC since 2010, of Back Holdings, LLC since 2007 and of Jabb Associates, Inc. since 1997. Mr. Adams has also held the position of Chairman and has been a principal owner of Texas Appliance Supply, Inc., a wholesale and retail distribution company, since 2007. Prior to its sale to Exxon Mobil Corporation in 2010, he served on the board of directors of XTO Energy Inc., where he chaired the Compensation and the Corporate Governance and Nominating committees. Previously, Mr. Adams had a 25-year career in commercial and energy banking, most recently as Executive Regional President of Texas Bank in Fort Worth, before retiring in 2006. He also served as President of Frost Bank-Arlington. Mr. Adams received a B.B.A. in Finance from Texas Tech University.

We believe that Mr. Adams’ strong track record of leading companies, including his participation on the boards of several companies, and his knowledge of the industry, make him well suited to serve as a member of our board of directors.

Key Employees of Our General Partner

The following table sets forth certain information regarding the current key employees of our general partner upon consummation of this offering.


Name	Age		Position

Gary D. Simpson		60	Senior Vice President

Brandon L. Neely		37	Vice President of Asset Development

Allen L. (“Law”) Armstrong, Jr.		39	Vice President of Land, Permian Basin

Bill Frey		63	Vice President of Operations

Dave Pearson		48	Vice President of Land, San Juan

Gary D. Simpson—Senior Vice President. Gary D. Simpson will serve as a Senior Vice President. He has been a consultant at MorningStar since its founding in 2012. He previously served as Senior Vice President of Investor Relations & Finance and board member at XTO prior to its acquisition by Exxon in 2010. With decades of energy and corporate experience, Gary has worked in the international arena and domestic energy production operations. Recently, he has guided Simpson Investments, Inc. as President, with a portfolio focused on equities, commodities and active assets. Gary’s prior company affiliations include XTO, Simpson Oil & Land Company, Arco International Oil & Gas, Inc. and Exxon. Mr. Simpson received a B.S. (1985) in Petroleum

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Engineering from Texas A&M University, magna cum laude, and an M.F.A. (1996) from the American Film Institute (AFI). Gary is the nephew of Bob R Simpson.

Brandon L. Neely—Vice President—Asset Development. Brandon L. Neely will serve as our Vice President of Asset Development. He joined MorningStar in 2017 and served as Manager—Reservoir Engineering since December 2018. Prior to joining MorningStar, Brandon was the Team Lead at Uinta Basin for Finley Resources, where he was responsible for implementing asset development programs and optimization along with identifying future growth opportunities for the company. Brandon began his career at XTO as a Reservoir Engineer working East Texas properties. He graduated from the Colorado School of Mines in 2008 with a B.S. in Petroleum Engineering and a B.S. in Economics.

Allen L. (“Law”) Armstrong, Jr—Vice President of Land—Permian Basin. Allen Law Armstrong, Jr will serve as our Vice President of Land—Permian Basin. He previously served as Area Land Manager—Permian Basin of MorningStar since 2018. Prior to joining MorningStar, he was employed by XTO as a Landman in the Barnett Shale and Delaware Basin divisions from 2012 until 2018. Prior to joining XTO, he worked as an Independent Landman from 2007 until 2012. He graduated from Texas Christian University with a B.S. in Political Science.

Bill Frey—Vice President of Operations. Bill Frey will serve as our Vice President of Operations. He joined MorningStar in 2014, and now has over 40 years of experience in the oil and gas industry. Bill has held a variety of management, supervisory, and technical positions with Basa Resources, Plains Resources, Stocker Resources, Oryx Energy, and its predecessor Sun Exploration and Production Company. Bill also operated a consulting firm, Frey Engineering, specializing in operational and asset management, and providing petroleum engineering services for clients, and was a partner in another consulting firm Evans, Frey, and Walker. Bill graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. He has served as the Secretary of the Fort Worth Chapter of the Society of Petroleum Engineers. He is a registered professional engineer in Texas and California, and a lifetime member of the Society of Petroleum Engineers.

Dave Pearson—Vice President of Land—San Juan. Dave Pearson will serve as the Vice President of Land—San Juan. He previously served as a Senior Landman and Land Manager, managing various assets in multiple states since joining MorningStar in 2017. He worked as a Landman at XTO, ultimately becoming Senior Staff Landman in 2015, before coming to MorningStar. Prior to joining XTO in 2011, Dave worked as a contract Landman providing acquisition due diligence and acquisition support primarily for XTO, as well as other oil and gas companies. He graduated from the University of Oklahoma with a Bachelor of Science in Zoology.

Southland Bankruptcy

On January 27, 2020, Southland filed a voluntary petition in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). With the approval of the Bankruptcy Court, in May 2020 Southland sold its assets in the San Juan Basin to MorningStar Partners L.P. for $10.2 million. At the time of filing for bankruptcy and the Bankruptcy Court’s approval of its plan of reorganization, Bob R. Simpson, Scott T. Agosta, Keith A. Hutton, and Brent W. Clum were acting or former officers of Southland and were affiliates of MorningStar Partners L.P. As of the date of this prospectus, none of these individuals are employed by or affiliated with Southland.

Reimbursement of Expenses of Our General Partner

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partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Board of Directors

Prior to the date that our common units are first traded on the NYSE, we expect our general partner to have a seven-member board of directors.

In evaluating director candidates, the sole member of our general partner will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the Board to fulfill their duties.

Our general partner’s directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

Director Independence

Our independent directors will meet the independence standards established by the NYSE listing rules.

Committees of the Board of Directors

The Board will have an audit committee, a compensation committee, a conflicts committee, and such other committees as the Board shall determine from time to time. The NYSE listing rules do not require a listed limited partnership to establish a compensation committee or a nominating and corporate governance committee. However, we have established a compensation committee that will have the responsibilities set forth below.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE listing rules and rules of the SEC. The audit committee will assist the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management. Effective upon the consummation of this offering, Rick J. Settle, Phillip R. Kevil and Bill H. Adams III will serve on the audit committee. Rick J. Settle will serve as chair of the audit committee.

Conflicts Committee

In accordance with the terms of our partnership agreement, at least two members of the Board will serve on our conflicts committee to review specific matters that may involve conflicts of interest. The members of our conflicts committee cannot be officers or employees of our general

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partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner or its affiliates or any interest in us or our subsidiaries other than common units or awards, if any, under our incentive compensation plan. We expect that Rick J. Settle, Phillip R. Kevil and Bill H. Adams III will serve as members of our conflicts committee. Please read “Conflicts of Interest and Duties.”

Compensation Committee

Effective upon the consummation of this offering, the members of our compensation committee will be Phillip R. Kevil, J. Luther King, Jr. and Bill H. Adams III, who will also serve as chair of the compensation committee. Each of the members of our compensation committee will be independent under the applicable rules and regulations of the NYSE, will be a “non-employee director” as defined in Rule 16b-3 promulgated under the Exchange Act and will be an “outside director” as that term is defined in Section 162(m) of the Code (Section 162(m)). The compensation committee will operate under a written charter that satisfies the applicable standards of the SEC and the NYSE.

The compensation committee’s responsibilities include:

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annually reviewing and approving corporate goals and objectives relevant to compensation of our chief executive officer and our other executive officers;

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annually reviewing and making recommendations to our board of directors with respect to the compensation of our chief executive officer and determining the compensation for our other executive officers;

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reviewing and making recommendations to our board of directors with respect to director compensation; and

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overseeing and administering our equity incentive plans.

From time to time, our compensation committee may use outside compensation consultants to assist it in analyzing our compensation programs and in determining appropriate levels of compensation and benefits. The compensation committee will review and evaluate, at least annually, the performance of the compensation committee and its members, including compliance by the compensation committee with its charter.

Board Leadership Structure

Leadership of our general partner’s board of directors is vested in a Chairman of the Board. Mr. Bob Simpson currently serves as a Director and the Chairman of the Board, and we have no policy with respect to the separation of the offices of chairman of the Board and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the Board are designated or elected by the Founders. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

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Board Role in Risk Oversight

Our corporate governance guidelines will provide that the Board is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

General

We do not directly employ any of the persons responsible for managing our business. Our general partner’s executive officers will manage our business as part of the services provided by our general partner to us under our partnership agreement. Although all of the employees that conduct our business are either employed by our general partner or its subsidiaries, we sometimes refer to these individuals in this prospectus as our employees.

All of our general partner’s executive officers and other employees necessary to operate our business will be employed and compensated by either our general partner or a subsidiary of the general partner, subject to reimbursement by our general partner. The compensation for all of our executive officers will be indirectly paid by us to the extent provided for in the partnership agreement because we will reimburse our general partner for compensation it pays related to management of our business. Please see “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Reimbursement of Expenses of Our General Partner.”

Our compensation committee will have responsibility for reviewing and making recommendations to our board of directors with respect to the compensation of our chief executive officer and determining the compensation of our other executive officers. Our predecessor historically compensated certain of its executive officers primarily with base salary and cash bonuses. However, in connection with this offering, the compensation committee may consider the compensation structures and levels that they believe will be necessary for executive recruitment and retention for us as a public company.

Emerging Growth Company Status

As an emerging growth company we are exempt from certain requirements related to executive compensation, including the requirements to hold a nonbinding advisory vote on executive compensation and to provide information relating to the ratio of total compensation of our chief executive officer to the median of the annual total compensation of all of our employees, each as required by the Investor Protection and Securities Reform Act of 2010, which is part of the Dodd-Frank Wall Street Reform and Consumer Protection Act. The rules applicable to emerging growth companies require compensation disclosure for any individuals serving as our principal executive officer during the last completed fiscal year and the two most highly compensated executive officers other than our principal executive officer, as well as up to two additional individuals who would have been one of the two most highly compensated executive officers had they remained employed as of the last day of the year. We refer to these officers as our “Named Executive Officers” or “NEOs”.

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Summary Compensation Table

The following table sets forth compensation for our NEOs, for the years ended December 31, 2022 and 2021.


Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)⁽³⁾		Value of All Other Compensation ($)⁽¹⁾		Total Compensation ($)
Bob R. Simpson		2022		—		—		—		—		—
CEO, Chairman, and Director⁽²⁾		2021		—		—		—		—		—

Brent W. Clum		2022		262,500		220,000		—		9,150		491,650
President of Business Operations, CFO, and Director		2021		250,000		75,000		2,400,000		8,700		2,733,700

Keith A. Hutton⁽⁴⁾		2022		—		—		—		—		—
President of Production and Development Director		2021		—		—		—		—		—

Scott T. Agosta		2022		280,000		100,000		—		9,150		389,150
Chief Accounting Officer		2021		250,000		50,000		—		8,700		308,700

(1)	The amounts disclosed in this column reflect matching contributions made on behalf of employees under our 401(k) plan.

(2)	Mr. Simpson was appointed as Chief Executive Officer in July 2022. Mr. Simpson did not receive any compensation in his capacity as Chief Executive Officer or as Chairman and Director of the Board in 2021 or 2022.

(3)

Amounts reported represent the aggregate grant date fair value of common units award to the named executive officers in fiscal year 2021, calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation – Stock Compensation, calculated based on the fair market value of a common unit as of the grant date and the number of common units subject to award. The assumptions in determining the valuation of the unit awards are found in footnote 11 to the Consolidated Financial Statements.

(4)	Mr. Hutton was appointed as President of Production and Development in July 2022, prior to which he served as our Chief Executive Officer. Mr. Hutton did not receive any compensation in his capacity as an officer or director in 2021 or 2022.

Long-Term Incentive Plan

Our general partner intends to adopt the TXO Energy Partners, L.P. 2023 Long-Term Incentive Plan (the “LTIP”) under which our general partner may issue long-term equity based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under the LTIP and all determinations with respect to awards to be made under the LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the terms that are currently expected to be included in the LTIP.

General

The LTIP will provide for the grant, from time to time at the discretion of the board of directors of our general partner or any delegate thereof, subject to applicable law, of cash awards, unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us,

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and to align the economic interests of such individuals with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

Cash Awards

The plan administrator of the LTIP, in its discretion, may grant cash awards, either as standalone awards or in tandem with other awards. A cash award is an award denominated in cash.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the plan administrator, cash equal to the fair market value of a common unit. The plan administrator of the LTIP may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the plan administrator may determine are appropriate, including the period over which restricted units or phantom units will vest. The plan administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The plan administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the plan administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the plan administrator of the LTIP may establish.

Profits Interest Units

Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the plan administrator, may

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consist of profits interest units. The plan administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of another unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, another unit-based award may be paid in cash and/or in units (including restricted units) or any combination thereof as the plan administrator of the LTIP may determine.

Source of Common Units

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the plan administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the plan administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the plan administrator of the LTIP shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the plan administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the plan administrator deems appropriate to reflect the applicable transaction or event.

Termination of Service

The consequences of the termination of a grantee’s membership on the board of directors of our general partner or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.

Amendment or Termination of Long-Term Incentive Plan

The plan administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The plan

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administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Internal Revenue Code.

Expected Grants in Connection with the Offering

In connection with the closing of this offering, we expect to make awards of 545,000 phantom units with distribution equivalent rights as long-term incentive awards pursuant to the LTIP. These phantom units will vest in one-third increments on each of the first three anniversaries of the pricing date of this offering provided that the recipient remains employed through the anniversary date, and will be settled in common units as soon as reasonably practicable after the vesting date. Distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units, on the next payroll dates after the distribution is paid to holders of common units.

All outstanding and unvested phantom units will vest in the event that the officer’s employment is terminated without “cause” or by the officer for “good reason” (each as defined in the LTIP and the award agreement) within the two year period following a “change in control” (as defined in the LTIP). Additionally, the Compensation Committee may determine, in its discretion, to vest unvested phantom units in the event that the officer’s employment is terminated for reasons other than “cause”.

We have approved grants in the following amounts in connection with the closing of this offering, with the number of units underlying the award to be determined by dividing the target award amount by the public offering price set forth on the cover page of this prospectus: $1,000,000 to each of Mr. Clum and Mr. Agosta. In addition, we expect to make grants totaling approximately $8,900,000 to our directors and certain key employees.

Outstanding Equity Awards at 2022 Year-End

No NEO held an outstanding equity award as of December 31, 2022.

Employment Contracts, Termination of Employment, Change-in-Control Arrangements

We currently do not have any employment agreements or other plans or arrangements with our executive officers that would result in payments to be made by us to an NEO upon the resignation, retirement or any other termination of an NEO’s employment or upon a change in control.

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner. The non-employee director compensation program will consist of annual equity-based awards granted under the LTIP having a value as of the grant date of approximately $60,000 and an additional $30,000 in equity-based award for service as the chair of a committee of the board of directors. Initial awards are expected to be made to our non-employee directors in connection with the closing of the offering.

Non-employee directors will also receive reimbursement for out-of-pocket expenses they incur in connection with attending meetings of the board of directors or its committees. Each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common units that, upon the consummation of this offering and the related transactions, will be owned by:

•

beneficial owners of more than 5% of our common units;

•

each named executive officer of our general partner; and

•

all directors, director nominees and executive officers of our general partner as a group.

The table assumes the underwriters’ option to purchase additional common units from us is not exercised. The percentage of units beneficially owned is based on 30,000,000 common units being outstanding immediately following this offering.

In connection with the Reorganization Transactions prior to this offering each of the Existing Owners will contribute their interests in us to MorningStar Partners II, LP (“MSP II”) in exchange for equity interests in MSP II (the “MSP II Units”). The Existing Owners will be entitled to have their MSP II Units exchanged for common units on a one-for-one basis at any time. As a result, the number of common units listed in the table below correlates to the number of MSP II Units the Existing Owners will own immediately prior to and after this offering.

The following table does not include (i) any common units that our directors, director nominees, officers, and certain individuals identified by us may purchase in this offering through the directed unit program described under “Underwriting” and (ii) any of the 545,000 phantom units that will be awarded to certain of our directors, executive officers and key employees in connection with this offering as further described under “Executive Compensation and Other Information—Expected Grants in Connection with the Offering.”


	Common Units to be Beneficially Owned		Percentage of Common Units to be Beneficially Owned

Name of Beneficial Owner(1)

5% Unitholders:

Global Endowment Management, LP(2)		4,713,962		16	%

Luther King Capital Management(3)		3,295,474		11	%

Named Executive Officers, Directors and Director Nominees

Bob R. Simpson		4,123,110		14	%

Brent W. Clum		279,406		1	%

Keith A. Hutton		2,942,215		10	%

Scott T. Agosta		58,462		—

Phillip R. Kevil		9,584		—

Rick J. Settle		11,716		—

J. Luther King, Jr.(3)		3,295,474		11	%

Bill H. Adams III		54,284		—

All executive officers, directors and director nominees as a group ( 8 persons)		10,774,251		36	%

(1)

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Each of the holders listed has sole voting and investment power with respect to the common units beneficially owned by the holder unless noted otherwise, subject to community property laws where applicable. Unless otherwise noted, the address for each beneficial owner listed below is 400 W 7th St., Fort Worth, TX 76102.

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(2)

Represents (i) 1,670,731 common units held by GEF-DTOE, Inc. and (ii) 3,043,232 common units held by GEF-PUE, LP. Global Endowment Management, LP controls the investment decisions of each of GEF-DTOE, Inc. and GEF-PUE, LP, and J. Porter Durham, Jr. has management control over Global Endowment Management, LP and accordingly may be deemed to share beneficial ownership of the common units held by each of GEF-DTOE, Inc. and GEF-PUE, LP. J. Porter Durham, Jr. disclaims beneficial ownership of such common units. The principal address for each of the above referenced entities is c/o Global Endowment Management, LP 224 W. Tremont Ave. Charlotte, NC 28203.

(3)	Represents (i) 1,189,400 common units held by LKCM Investment Partnership, L.P, and (ii) 1,372,130 common units held by PDLP Morningstar, LLC, a wholly owned subsidiary of LKCM Private Discipline Master Fund, SPC.

LKCM Investment Partnership GP, LLC is the general partner of LKCM Investment Partnership, L.P., and J. Luther King, Jr. serves as the President and has voting and investment power over the securities held by LKCM Investment Partnership GP, LLC. LKCM Private Discipline Management, L.P. is the sole holder of management shares of LKCM Private Discipline Master Fund, SPC and J. Luther King has voting and investment power over the securities held by LKCM Private Discipline Management L.P.

Accordingly, J. Luther King may be deemed to share beneficial ownership of the common units held by each of LKCM Investment Partnership, L.P. and PDLP Morningstar, J. Luther King disclaims beneficial ownership of such common units. The principal address for each of the above referenced entities is 301 Commerce Street, Suite 1600, Fort Worth, Texas 76102.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Upon the consummation of this offering, assuming the underwriters do not exercise their option to purchase additional common units, the Founders will own 8,028,129 common units representing an approximate 27% limited partner interest in us, and MSOG, which is owned by the Founders, will own and control our general partner. The Founders, who own MSOG, will indirectly appoint all of the directors of our general partner, which will own a non-economic general partner interest in us. These percentages do not reflect any common units that may be issued under the long-term incentive plan that our general partner expects to adopt prior to the closing of this offering.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s length negotiations.


*Operational Stage*
Distributions of available cash to affiliates of our general partner		We make cash distributions to our unitholders, including affiliates of our general partner, pro rata.

		Upon completion of this offering, the affiliates of our general partner will own 11,457,649 common units, representing approximately 38% of our outstanding common units and would receive a pro rata percentage of the cash distributions that we distribute in respect thereof.

Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner and its affiliates for costs and expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “Our Partnership Agreement—Withdrawal or Removal of Our General Partner.”

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Liquidation Stage

Liquidation

Upon our liquidation, the partners, including our general partner with respect to any common units or other units then held by our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with Affiliates in Connection with the Reorganization Transactions

In connection with the closing of this offering, we, our general partner and its affiliates will enter into the various documents and agreements that will affect the Reorganization Transactions. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

Contribution Agreement

In connection with the closing of this offering, the Existing Owners will contribute all of our outstanding equity interests in the partnership to a newly formed parent company, MorningStar Partners II, L.P., or MSP II, in exchange for equity interests in MSP II that are identical to the equity interests owned in the partnership. Following this contribution and immediately prior to the offering, all of our equity interests will be held by MSP II.

Other Transactions with Related Persons

We occupy a building owned by MorningStar Capital LLC, a limited liability company owned by Mr. Simpson, our Chief Executive Officer and the Chairman of the Board. In lieu of paying rent, we paid property taxes and paid for repairs and maintenance on behalf of MorningStar Capital LLC in the amount of $0.2 million in the first nine months of 2022, $0.9 million in 2021 and $1.5 million in 2020.

Procedures for Review, Approval or Ratification of Transactions with Related Persons

We expect that the Board will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the Board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the Board any conflict or potential conflict of interest that may arise between the director in his or her personal capacity or any affiliate of the director in his or her personal capacity, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the Board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the Board in accordance with the provisions of our partnership agreement. At the discretion of the Board in light of the circumstances, the resolution may be determined by the Board in its entirety, by the conflicts committee of the Board or by approval of our unitholders (other than the general partner and its affiliates).

Upon our adoption of our code of business conduct, we would expect that any executive officer will be required to avoid personal conflicts of interest unless approved by the Board.

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Please read “Conflicts of Interest and Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the Founders) on the one hand, and us and our limited partners, on the other hand. In certain cases, directors and officers of our general partner have duties to manage our general partner at the direction of MSOG, which is owned by the Founders. At the same time, our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership. The Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically limits the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the Board or from our unitholders. There is no requirement under our partnership agreement that our general partner seek the approval of the conflicts committee or our unitholders for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the conflicts committee or our unitholders on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, our general partner will consider a variety of factors, including the nature of the conflict, the size and dollar amount involved, the identity of the parties involved and any other factors the Board deems relevant in determining whether it will seek approval from the conflicts committee or our unitholders. Whenever our general partner makes a determination to refer or not to refer any potential conflict of interest to the conflicts committee for approval or to seek or not to seek unitholder approval, our general partner is acting in its individual capacity, which means that it may act free of any duty or obligation whatsoever to us or our unitholders and will not be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under applicable law, other than the implied contractual covenant of good faith and fair dealing. For a more detailed discussion of the duties applicable to our general partner, as well as the implied contractual covenant of good faith and fair dealing, please read “—Duties of Our General Partner.”

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our limited partners if the resolution of the conflict is:

•

approved by the conflicts committee, which our partnership agreement defines as “special approval”;

•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

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•

determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•

determined by the Board to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from the conflicts committee or our unitholders and our general partner’s board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he or she is acting in a manner that is not adverse to the best interests of the partnership or that the determination to take or not to take action meets the specified standard; for example, the person may determine that a transaction is being entered into on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or is “fair and reasonable” to us. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates that does not receive unitholder or conflicts committee approval, must be determined by the Board to be:

•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•

“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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Our general partner’s affiliates may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might directly compete with us. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest.

Our partnership agreement contains provisions that permissibly modify and reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in a manner not adverse to the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners at the time our partnership agreement was entered into where the language in our partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right or its voting rights with respect to the units it owns, whether to exercise its registration rights, and whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.

We do not have any officers or employees and rely solely on officers and employees of our general partner and its affiliates.

Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. There could be material competition for the time and effort of the officers and employees who provide services to our general partner.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.

Our partnership agreement:

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and our general partner has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

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provides that our general partner shall not have any liability to us or our limited partners for decisions made in its capacity so long as such decisions are made in good faith;

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•

generally provides that in a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our public common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the cases may be, acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

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the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for equity interests of the partnership, and the incurring of any other obligations;

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the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

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the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;

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the negotiation, execution and performance of any contracts, conveyances or other instruments;

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the distribution of cash held by the partnership;

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the selection and dismissal of employees and agents, attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

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the maintenance of insurance for our benefit and the benefit of our partners and indemnitees;

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•

the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

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the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

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the indemnification of any person against liabilities and contingencies to the extent permitted by law;

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the purchase, sale or other acquisition or disposition of our equity interests, or the issuance of additional options, rights, warrants and appreciation rights relating to our equity interests; and

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the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.

We will reimburse our general partner and its affiliates for expenses.

Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates for costs and expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine such other expenses that are allocable to us, and our partnership agreement does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. Such reimbursements will be made prior to making any distributions on our common units. Please read “The Partnership Agreement—Reimbursement of Expenses.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party to such agreements has recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement permits our general partner to limit its or our liability, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliates or to us free of any liability or obligation to us or our partners. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

Limited partners have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the limited partners, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Duties of our General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied contractual covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners at the time the partnership agreement was entered into where the language in our partnership agreement does not provide for a clear course of action.

As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited or restricted by state-law fiduciary standards and to take into account the interests of other parties in addition to or in lieu of our interests when resolving conflicts of interest. We believe this is appropriate and necessary because, in certain cases, the Board has duties to manage our general partner at the direction of MSOG, which is owned by the Founders. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the limited partners because they restrict the remedies available to limited partners for actions that, without those provisions, might constitute breaches of fiduciary duty, as described below and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

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the fiduciary duties imposed on general partners of a limited partnership by Delaware law in the absence of partnership agreement provisions to the contrary;

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the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties referenced in the preceding bullet that would otherwise be imposed by Delaware law on our general partner; and

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certain rights and remedies of our limited partners contained in our partnership agreement and the Delaware Act.

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Delaware law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner of a Delaware limited partnership to use that amount of care that an ordinarily careful and prudent person would use in similar circumstances and to consider all material information reasonably available in making business decisions. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transaction were entirely fair to the partnership. Our partnership agreement modifies these standards as described below.

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it subjectively believed that the decision was not adverse to our best interests, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation whatsoever to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not

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approved by the public common unitholders or the conflicts committee of the Board must be determined by the Board to be:

•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or, our limited partners for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

Rights and remedies of limited partners

The Delaware Act favors the principles of freedom of contract and enforceability of partnership agreements and allows our partnership agreement to contain terms governing the rights of our unitholders. The rights of our unitholders, including voting and approval rights and the ability of the

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partnership to issue additional units, are governed by the terms of our partnership agreement. Please read “The Partnership Agreement.” As to remedies of unitholders, the Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, each common unitholder will be deemed to have agreed to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “Description of the Common Units—Transfer Agent and Register—Transfer of Common Units.” This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign our partnership agreement does not render our partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or these persons acted in bad faith or engaged in intentional fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was criminal. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the U.S. federal securities laws, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. Please read “The Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

Computershare Trust Company, N.A. will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by our unitholders:

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surety bond premiums to replace lost or stolen certificates or to cover taxes and other governmental charges;

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special charges for services requested by a common unitholder; and

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other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of their actions for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the indemnitee.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

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represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

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automatically agrees to be bound by the terms and conditions of our partnership agreement; and

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•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. Our general partner will cause any transfers to be recorded on our books and records from time to time (or shall cause the transfer agent to do so, as applicable).

The transferor of common units will have a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor will not have a duty to insure the execution of the transfer application and certification by the transferee and will have no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application and certification to the transfer agent.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing transfers of securities.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

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with regard to distributions of available cash, please read “Our Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions;”

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with regard to the duties of our general partner, please read “Conflicts of Interest and Duties;”

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with regard to the transfer of common units, please read “Description of the Common Units—Transfer Agent and Registrar—Transfer of Common Units;” and

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with regard to allocations of taxable income, taxable loss and other matters, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized under Delaware law and will have a perpetual existence unless dissolved, wound up and terminated pursuant to the terms of our partnership agreement and the Delaware Act.

Purpose

Our purpose under our partnership agreement is to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law. However, our general partner may not cause us to engage, directly or indirectly, in any business activity that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, except as otherwise provided below under “—Election to be Treated as a Corporation.”

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the ownership, acquisition, exploitation and development of oil and natural gas properties and the ownership, acquisition and operation of related assets, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described under “—Limited Liability.”

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Limited Voting Rights

The following is a summary of the unitholder vote required for each of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the common units.

Various matters require the approval of a “unit majority,” which means:

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the approval of a majority of the outstanding common units.

At the closing of this offering, the affiliates of our general partner (including the Founders) will have the ability to significantly influence the passage of, as well as the ability to significantly influence the defeat of, any amendment which requires a unit majority by virtue of their approximately 38% ownership of our common units.

In voting their common units, our general partner and its affiliates (including the Founders) will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. The holders of a majority of the common units (including common units deemed owned by our general partner and its affiliates) entitled to vote at the meeting, represented in person or by proxy shall constitute a quorum at a meeting of common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.

Issuance of additional units

No approval right. Please read “—Issuance of Additional Partnership Interests.”

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority, in certain circumstances. Please read “—Merger, Consolidation, Sale or Other Disposition of Assets.”

Dissolution of our partnership

Unit majority. Please read “—Termination and Dissolution.”

Continuation of our business upon certain events of dissolution

Unit majority. Please read “—Termination and Dissolution.”

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates (including the Founders), is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

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Removal of our general partner

Not less than 66²⁄₃% of the outstanding common units, including units held by our general partner and its affiliates (including the Founders), voting as a single class. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest

Our general partner may transfer any or all of its general partner interest in us without a vote of our unitholders. Please read “—Transfer of General Partner Interest.”

Transfer of ownership interests in our general partner

No unitholder approval required. Please read “—Transfer of Ownership Interests in Our General Partner.”

Election to be treated as a corporation

No approval right. Please read “—Election to be Treated as a Corporation.”

The limited liability company agreement of our general partner provides that the board of directors of our general partner will not take any action without approval of MSOG, the sole member of our general partner, with respect to an extraordinary matter that would have, or would reasonably be expected to have, a material effect, directly or indirectly, on MSOG’s interests in our general partner. Extraordinary matters include, but are not limited to:

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the commencement of any action relating to bankruptcy, insolvency, reorganization or relief of debtors by our general partner, us or any of our subsidiaries or joint ventures,

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a merger, consolidation, recapitalization or similar transaction involving our general partner, us or any of our material subsidiaries or joint ventures,

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a sale, exchange or other transfer not in the ordinary course of business of a substantial portion of the assets of ours, our general partner or any of our subsidiaries or joint ventures, viewed on a consolidated basis, in one or a series of related transactions,

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the issuance or repurchase of any equity interests in our general partner or a joint venture,

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a dissolution or liquidation of our general partner, us or any of our material subsidiaries or joint ventures, and

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any material amendment of the governing documents of a joint venture, or a transfer, sale or other disposition of by us, our general partner or any of our subsidiaries of equity interests in a joint venture.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

•

brought in a derivative manner on our behalf;

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asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

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•

asserting a claim arising pursuant to any provision of the Delaware Act; or

•

asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. The foregoing provision will not apply to any claims as to which the Court of Chancery determines that there is an indispensable party not subject to the jurisdiction of such court, which is rested in the exclusive jurisdiction of a court or forum other than such court (including claims arising under the Exchange Act), or for which such court does not have subject matter jurisdiction, or to any claims arising under the Securities Act and, unless we consent in writing to the selection of an alternative forum, the United States federal district courts will be the sole and exclusive forum for resolving any action asserting a claim arising under the Securities Act. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules or regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain such Securities Act claims. To prevent having to litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, the partnership agreement provides that, unless we consent in writing to the selection of an alternative forum, United States federal district courts shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. There is uncertainty as to whether a court would enforce the forum provision with respect to claims under the federal securities laws.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other courts in Delaware) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he or she otherwise acts in conformity with the provisions of our partnership agreement, his or her liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he or she is obligated to contribute to us for his or her

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common units plus his or her share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by our limited partners as a group:

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to remove or replace our general partner;

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to approve some amendments to the partnership agreement; or

•

to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our operating subsidiary conducts business in New Mexico, Colorado and Texas, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as an owner of our operating subsidiary may require compliance with legal requirements in the jurisdictions in which our operating subsidiary conducts business, including qualifying our operating subsidiary to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership in our subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

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Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting or other rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to our common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. To adopt a proposed amendment, other than the amendments discussed below under “—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

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enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

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enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

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The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates (including the Founders)). Upon the consummation of this offering, affiliates of our general partner (including the Founders) will own an aggregate of approximately 38% of our outstanding common units, (excluding any common units purchased by our directors , executive officers and certain individuals identified by us) under our directed unit program), representing an aggregate of approximately 38% of our outstanding limited partnership units.

No Limited Partner Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

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a change in our name, the location of our principal place of business, our registered agent or our registered office;

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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

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a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we, nor our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes, except as otherwise provided below under “—Election to be Treated as a Corporation”;

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a change in our fiscal year or taxable year and related changes;

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from being subjected, in any manner, to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

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an amendment that sets forth the designations, preferences, rights, powers and duties of any class or series of additional partnership securities or rights to acquire partnership securities, that our general partner determines to be necessary or appropriate or advisable for the authorization or issuance of additional partnership securities or rights to acquire partnership securities;

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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

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an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

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any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, limited liability company, joint venture or other entity, as otherwise permitted by our partnership agreement;

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any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether such limited partner is subject to United States federal income taxation on the income generated by us and to provide for the ability of our general partner to redeem the units of any limited partner who fails to provide such statement, certification or other evidence;

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an amendment that our general partner determines to be necessary or appropriate or advisable in connection with conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

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do not adversely affect our limited partners (or any particular class of limited partners) in any material respect;

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

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are necessary or appropriate to facilitate the trading of our units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our units are or will be listed for trading;

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

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are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding common units unless we first obtain such an opinion.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the holders of the type or class of units so affected, but no vote will be required by the holders of any class or classes or type or types of units that our general partner determines are not adversely affected in any material respect. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that would increase the percentage of units

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required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

Merger, Consolidation, Sale or Other Disposition of Assets

A merger, consolidation, or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation, or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interest of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us, among other things, to sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including by way of merger, consolidation, conversion or other combination or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger, consolidation or conversion without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in an amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of the other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger, consolidation or conversion, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner, other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or a withdrawal or removal followed by approval and admission of a successor;

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the election of our general partner to dissolve us, if approved by the holders of a unit majority;

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the entry of a decree of judicial dissolution of our partnership pursuant to the provisions of the Delaware Act; or

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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law.

Upon a dissolution under the first bullet above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of a unit majority, subject to our receipt of an opinion of counsel to the effect that:

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the action would not result in the loss of limited liability under Delaware law of any limited partner; and

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neither our partnership nor our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2032 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates (including the Founders), and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2032, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving at least 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates (including the Founders). In addition, our partnership agreement permits our general partner to sell or otherwise transfer all of its general partner interest in us without the approval of our unitholders. Please read “—Transfer of General Partner Interest.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²⁄₃% of our outstanding units, voting together as a single class, including

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units held by our general partner and its affiliates (including the Founders), and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units. The ownership of more than 33¹⁄₃% of our outstanding units by our general partner and its affiliates (including the Founders) would give them the practical ability to prevent our general partner’s removal. Upon the consummation of this offering, affiliates of our general partner (including the Founders) will own an aggregate of approximately 38% of our outstanding common units, (excluding any common units purchased by our directors, executive officers and certain individuals identified by us) under our directed unit program), representing approximately 38% of our outstanding limited partnership units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist our general partner will have the right to convert its general partner interest into common units or to receive cash from the successor general partner in exchange for those interests based on the fair market value of the interests at the time.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and its affiliate and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and its affiliate and the successor general partner will determine the fair market value. If the departing general partner and its affiliate and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Our general partner may transfer all or any of its general partner interest to an affiliate or a third party without the approval of our unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates (including the Founders) may at any time transfer common units to one or more persons without unitholder approval.

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Transfer of Ownership Interests in Our General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Election to be Treated as a Corporation

If at any time our general partner determines that (i) we should no longer be characterized as a partnership but instead as an entity taxed as a corporation for U.S. federal income tax purposes or (ii) common units held by some or all unitholders should be converted into or exchanged for interests in a newly formed entity taxed as a corporation for U.S. federal income tax purposes whose sole asset is interests in us (“parent corporation”), then our general partner may, without unitholder approval, reorganize us and cause us to be treated as an entity taxable as a corporation for U.S. federal income tax purposes or cause us to engage in a merger or other transaction pursuant to which common units held by some or all unitholders will be converted into or exchanged for interests in the parent corporation. In addition, if our general partner causes partnership interests in us to be held by a parent corporation, our Existing Owners may choose to retain their partnership interests in us rather than convert or exchange their partnership interests into parent corporation shares. The general partner may take any of the foregoing actions if it in good faith determines (meaning it subjectively believes) that such action is not adverse to our best interests. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. The tax liability, if any, of a unitholder as a result of such an event may vary depending on the unitholder’s particular situation and may vary from the tax liability of each of our Existing Owners. Our general partner will have no duty or obligation to make any such determination or take any such actions, however, and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in a manner not adverse to the best interests of us or our limited partners.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates (including the Founders) acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the Board.

Limited Call Right

If at any time our general partner and its affiliates (including the Founders) own more than 80% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

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the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

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the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of its common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of common units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take such action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, entitled to vote at the meeting represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates (including the Founders) or a direct or subsequently approved transferee of our general partner or its affiliates or a transferee of that person or group approved by our general partner or a person or group specifically approved by our general partner or the Board, as applicable, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held by a nominee or in a street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent or an exchange agent.

Status as Limited Partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common

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units transferred when such transfer and admission is reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Unitholders; Redemption

We may acquire interests in oil and natural gas leases on United States federal lands in the future. To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, our general partner, acting on our behalf, may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption. Further, the units held by such unitholder will not be entitled to any voting rights and may not receive distributions in-kind upon our liquidation.

Furthermore, we have the right to redeem all of the common units of any holder that our general partner concludes is an Ineligible Holder or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.

Indemnification

Under our partnership agreement, unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events,:

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our general partner;

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any departing general partner;

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any person who is or was an affiliate of our general partner or any departing general partner;

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any person who is or was a director, officer, manager, managing member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

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any person who is or was serving as a director, officer, manager, managing member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

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any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation, and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year is the calendar year.

We will mail or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also mail or make available a report containing unaudited financial statements within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist it in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether such unitholder supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

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a current list of the name and last known address of each record holder;

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copies of our partnership agreement and our certificate of limited partnership and related amendments thereto; and

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certain information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, the Existing Owners will hold an aggregate of 25,000,000 common units. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Additionally, any common units purchased in this offering by officers and directors of our general partner under the directed unit program will be subject to the lock-up restrictions described below. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

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1.0% of the total number of the securities outstanding; or

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the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A unitholder who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Partnership Interests.”

Under our partnership agreement, our general partner and its affiliates, including the Founders, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other partnership interests that they hold, which we refer to as registerable securities. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any registerable securities to require registration of such registerable securities and to include any such registerable securities in a registration by us of common units or other partnership interests, including common units or other partnership interests offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. In connection with any registration of units held by our general partner or its affiliates, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Except as described below, our general partner and its affiliates may sell their common units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

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Lock-Up Agreements

MSP II, as the holder following the Reorganization Transactions of the common units currently held directly by the Existing Owners, the directors and executive officers of our general partner, and their respective affiliates, have agreed, subject to certain exceptions, not to sell any common units for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

Registration Statement on Form S-8

Prior to the completion of this offering, we expect to adopt a new long-term incentive plan (the “Long-Term Incentive Plan”). If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the Long-Term Incentive Plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the Long-Term Incentive Plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material U.S. federal income tax consequences that may be relevant to prospective common unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to TXO Energy Partners, and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and foreign persons eligible for the benefits of an applicable income tax treaty with the United States), individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, persons subject to special tax accounting rules as a result of any item of gross income with respect to our common units being taken into account in an applicable financial statement and persons deemed to sell their units under the constructive sale provisions of the Internal Revenue Code. In addition, the discussion only comments, to a limited extent, on state, local and foreign tax consequences. Accordingly, we encourage each prospective common unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable laws, including the impact of U.S. tax reform legislation.

No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units, including the prices at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of U.S. federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

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Notwithstanding the above, and for the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether all aspects of our method for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”); (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”); and (iv) whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction (please read “—Tax Treatment of Operations—Depletion Deductions”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation and marketing of certain minerals and natural resources, including crude oil, natural gas and other products of a type that are produced in a petroleum refinery or natural gas processing plant, certain related hedging activities, certain activities that are intrinsic to other qualifying activities, and our allocable share of our subsidiaries’ income from these sources. Other types of qualifying income include interest (other than from a financial business), dividends, real property rents, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 1% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

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We will be classified as a partnership for federal income tax purposes; and

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Each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.

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In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

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Neither we nor any of the operating subsidiaries has elected or will elect to be treated, or is otherwise treated, as a corporation for federal income tax purposes;

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For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

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Each commodity hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to the applicable Treasury Regulations, and has been and will be associated with oil, gas or products thereof that are held or to be held by us in activities of a type that Latham & Watkins LLP has opined or will opine result in qualifying income.

We believe that these representations have been true in the past, are true as of the date hereof and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts ), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

In addition, our general partner may, without unitholder approval, reorganize us and cause us to be treated as an entity taxable as a corporation for U.S. federal income tax purposes or cause us to enter into a transaction in which common units held by some or all unitholders will be converted into or exchanged for interests in a newly formed entity taxed as a corporation for U.S. federal income tax purposes whose sole asset is interests in us. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. Please read “The Partnership Agreement—Election to be Treated as a Corporation.”

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

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The discussion below is based on Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders of TXO Energy Partners will be treated as partners of TXO Energy Partners for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of TXO Energy Partners for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units in TXO Energy Partners. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in TXO Energy Partners for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections,” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro

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rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, depletion recapture, intangible drilling costs and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of taxable income to distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the year ending December 31, 2025, will be allocated, on a cumulative basis, an amount of U.S. federal taxable income for that period that will be 75% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. Our estimate is based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

The actual ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

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gross income from operations exceeds the amount required to make quarterly cash distributions from our available cash on all units, yet we only distribute the quarterly cash distributions from our available cash on all units;

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we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depletion, depreciation or amortization for U.S. federal income tax purposes or that is depletable, depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or

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legislation is enacted that limits or repeals certain U.S. federal income tax preferences currently available to oil and gas exploration and production companies (please read “—Recent Legislative Developments”).

Basis of Common Units.

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his

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share of our income, by any increases in his share of our nonrecourse liabilities and, on the disposition of a common unit, by his share of certain items related to business interest not yet deductible by him due to applicable limitations. Please read “—Limitations on Interest Deductions.” That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying properties, by any decreases in his share of our nonrecourse liabilities, by his share of our excess business interest (generally, the excess of our business interest over the amount that is deductible) and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations ) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The at risk limitation applies on an activity-by-activity basis, and in the case of oil and natural gas properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or natural gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer’s oil and natural gas properties. It is uncertain how this rule is implemented in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties we own in computing a unitholder’s at risk limitation with respect to us. If a unitholder were required to compute his at risk amount separately with respect to each oil or natural gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his common units as a whole.

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In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

An additional loss limitation may apply to certain of our unitholders for taxable years ending before January 1, 2026. A non-corporate unitholder will not be allowed to take a deduction for certain excess business losses in such taxable years. An excess business loss is the excess (if any) of a taxpayer’s aggregate deductions for the taxable year that are attributable to the trades or businesses of such taxpayer (determined without regard to the excess business loss limitation or any deduction allowable for net operating losses, qualified business income or capital losses) over the aggregate gross income or gain of such taxpayer for the taxable year that is attributable to such trades or businesses (subject to certain limitations in the case of capital gains) plus a threshold amount. The current threshold amount is equal to $270,000, or $550,000 for taxpayers filing a joint return. Any losses disallowed in a taxable year due to the excess business loss limitation may be used by the applicable unitholder in the following taxable year if certain conditions are met. Unitholders to which this excess business loss limitation applies will take their allocable share of our items of income, gain, loss and deduction into account in determining this limitation. This excess business loss limitation will be applied to a non-corporate unitholder after the passive loss limitations and may limit such unitholders’ ability to utilize any losses we generate allocable to such unitholder that are not otherwise limited by the basis, at-risk and passive loss limitations described above.

Limitations on Interest Deductions

Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business, “business interest”, may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our common units.

In addition, the deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

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interest on indebtedness properly allocable to property held for investment;

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our interest expense attributed to portfolio income; and

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the common unitholders in accordance with their percentage interests in us. If we have a net loss, that loss will be allocated to the common unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, as adjusted for certain items in accordance with applicable Treasury Regulations.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of this offering and (ii) any difference between the tax basis and fair market value of any property contributed to us that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all of our common unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. However, it may not be administratively feasible to make the relevant adjustments to “book” basis and the relevant reverse Section 704(c) Allocations each time we issue

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common units, particularly in the case of small or frequent common unit issuances. If that is the case, we may use simplifying conventions to make those adjustments and allocations, which may include the aggregation of certain issuances of common units. Latham & Watkins LLP is unable to opine as to the validity of such conventions. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts (subject to certain adjustments), if negative capital accounts (subject to certain adjustments) nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate such negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

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his relative contributions to us;

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the interests of all the partners in profits and losses;

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the interest of all the partners in cash flow; and

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the rights of all the partners to distributions of capital upon liquidation.

Latham & Watkins LLP is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

As a result, during this period:

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any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

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any cash distributions received by the unitholder as to those units would be fully taxable; and

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while not entirely free from doubt, all of these distributions would appear to be ordinary income.

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Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax Rates

Currently, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months ) of individuals is 20%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax, or NIIT, is imposed on certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins for such taxable year. The U.S. Department of the Treasury and the IRS have issued Treasury Regulations that provide guidance regarding the NIIT. Prospective common unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.

For taxable years ending on or before December 31, 2025, a non-corporate unitholder is entitled to a deduction equal to 20% of its “qualified business income” attributable to us, subject to certain limitations. For purposes of this deduction, a unitholder’s “qualified business income” attributable to us is equal to the sum of:

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the net amount of such unitholder’s allocable share of certain of our items of income, gain, deduction and loss (generally excluding certain items related to our investment activities, including capital gains and dividends, which are subject to a federal income tax rate of 20%); and

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any gain recognized by such unitholder on the disposition of its units to the extent such gain is attributable to certain Section 751 assets, including depreciation recapture and “inventory items” we own.

Prospective unitholders should consult their tax advisors regarding the application of this deduction and its interaction with the overall deduction for qualified business income.

Section 754 Election

We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election generally permits us to adjust a

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common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets (“common basis”) and (ii) his Section 743(b) adjustment to that basis.

We have adopted or will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

We will depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property that is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate such unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” Latham & Watkins LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

Subject to certain limitations, a Section 743(b) adjustment may create additional depreciable basis that is eligible for bonus depreciation under Section 168(k) to the extent the adjustment is attributable to depreciable property and not to goodwill or real property. However, because we

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may not be able to determine whether transfers of our units satisfy all of the eligibility requirements and due to other limitations regarding administrability, we may elect out of the bonus depreciation provisions of Section 168(k) with respect to basis adjustments under Section 743(b).

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer. Generally, a built-in loss is substantial if (i) it exceeds $250,000 or (ii) the transferee would be allocated a net loss in excess of $250,000 on a hypothetical sale of our assets for their fair market value immediately after a transfer of the interests at issue. In addition, a basis adjustment is required regardless of whether a Section 754 election is made if we distribute property and have a substantial basis reduction. A substantial basis reduction exists if, on a liquidating distribution of property to a unitholder, there would be a negative basis adjustment to our assets in excess of $250,000 if a Section 754 election were in place.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses”), unitholders will be

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entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. To qualify as an “independent producer” eligible for percentage depletion (and that is not subject to the intangible drilling and development cost deduction limits, please read “—Deductions for Intangible Drilling and Development Costs”), a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5.0 million per year in the aggregate. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral common units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral common units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

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The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.” We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs, or IDCs. IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a non-corporate unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is does not qualify as an independent producer under the rules disqualifying retailers and refiners from taking percentage depletion. Please read “—Depletion Deductions.”

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.”

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Lease Acquisition Costs

The cost of acquiring oil and natural gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “—Depletion Deductions.”

Geophysical Costs

The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred. The amortization period for certain geological and geophysical expenditures may be extended if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “—Recent Legislative Developments.”

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs, to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation, depletion and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our unitholders holding interests in us prior to any such offering. Please read “— Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable or depletable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery, depletion or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

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Valuation and Tax Basis of our Properties

The U.S. federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or determinations of basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables,” including potential recapture items such as depreciation, depletion, or IDC recapture, or to “inventory items” we own. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Ordinary income recognized by a unitholder on disposition of our units may be reduced by such unitholder’s deduction for qualified business income. Both ordinary income and capital gain recognized on a sale of units may be subject to the NIIT in certain circumstances. Please read “—Tax Consequences of Unit Ownership—Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the

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interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

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a short sale;

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an offsetting notional principal contract; or

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a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis in proportion to the number of days in each month and will be subsequently apportioned among our unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among our unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The U.S. Department of Treasury and the IRS have issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year.

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A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter through the month of disposition but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

We depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “—Tax Consequences of Unit Ownership—Section 754 Election,” Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any

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method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it. Further, a tax-exempt organization with more than one unrelated trade or business (including by attribution from investments in a partnership, such as us, that is engaged in one or more unrelated trades or businesses ) must compute its unrelated business taxable income separately for each such trade or business, including for purposes of determining any net operating loss deduction. As a result, it may not be possible for tax-exempt organizations to use losses from an investment in us to offset taxable income from another unrelated trade or business.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay U.S. federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular U.S. federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Gain on the sale or disposition of a common unit will be treated as effectively connected with a U.S. trade or business to the extent that a foreign unitholder would recognize gain effectively connected with a U.S. trade or business upon the hypothetical sale of our assets at fair market value on the date of the sale or exchange of that unit. Such gain shall be reduced by certain amounts treated as effectively connected with a U.S. trade or business attributable to certain real property interests, as set forth in the following paragraph.

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Under the Foreign Investment in Real Property Tax Act, a foreign common unitholder (other than certain “qualified foreign pension funds” (or an entity all of the interests of which are held by such a qualified foreign pension fund), which generally are entities or arrangements that are established and regulated by foreign law to provide retirement or other pension benefits to employees, do not have a single participant or beneficiary that is entitled to more than 5% of the assets or income of the entity or arrangement and are subject to certain preferential tax treatment under the laws of the applicable foreign country), generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future.

Therefore, foreign unitholders may be subject to U.S. federal income tax on gain from the sale or disposition of their units.

Upon the sale, exchange or other disposition of a common unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Quarterly distributions made to our foreign unitholders may also be subject to withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of, or distributions on, our common units occurring before January 1, 2023. Prospective foreign unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

Additional withholding requirements may also affect certain foreign unitholders. Please read “—Administrative Matters—Additional Withholding Requirements.”

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective common unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

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A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Similarly, for such taxable years, if the IRS makes audit adjustments to income tax returns filed by an entity in which we are a member or a partner, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our unitholders and former unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our common unitholders might be substantially reduced.

Additionally, pursuant to the Bipartisan Budget Act of 2015, we are required to designate a partner, or other person, with a substantial presence in the United States as the partnership representative (“Partnership Representative”). The Partnership Representative has the sole authority to act on our behalf for purposes of, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any person as the Partnership Representative. We currently anticipate that we will designate our general partner as our Partnership Representative. Further, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of our unitholders.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Internal Revenue Code) and certain other foreign entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or, subject to the proposed Treasury Regulations discussed below, gross proceeds from the sale or other disposition of any property of a type that can produce interest or dividends from sources within the United States (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Internal Revenue

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Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these requirements may be subject to different rules.

These rules generally apply to payments of FDAP Income currently and, while these rules generally would have applied to payments of relevant Gross Proceeds made on or after January 1, 2019, proposed Treasury Regulations eliminate these withholding taxes on payments of Gross Proceeds entirely. Unitholders generally may rely on these proposed Treasury Regulations until final Treasury Regulations are issued. Thus, to the extent we have FDAP Income that is not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other foreign entities, or persons that hold their common units through such foreign entities, may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective common unitholders should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

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the name, address and taxpayer identification number of the beneficial owner and the nominee;

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whether the beneficial owner is:

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a person that is not a U.S. person;

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a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

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a tax-exempt entity;

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the amount and description of units held, acquired or transferred for the beneficial owner; and

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specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for

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their own account. A penalty of $290 per failure, up to a maximum of $3,532,500 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed on taxpayers as a result of an underpayment of tax that is attributable to one or more specified causes, including: (i) negligence or disregard of rules or regulations, (ii) substantial understatements of income tax, (iii) substantial valuation misstatements and (iv) the disallowance of claimed tax benefits by reason of a transaction lacking economic substance or failing to meet the requirements of any similar rule of law. Except with respect to the disallowance of claimed tax benefits by reason of a transaction lacking economic substance or failing to meet the requirements of any similar rule of law, however, no penalty will be imposed for any portion of any such underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

With respect to substantial understatements of income tax, the amount of any understatement subject to penalty generally is reduced by that portion of the understatement which is attributable to a position adopted on the return: (A) for which there is, or was, “substantial authority”; or (B) as to which there is a reasonable basis and the relevant facts of that position are adequately disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must adequately disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty.

Recent Legislative Developments

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships.

In recent years, legislation has been proposed that would reduce or eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. Changes in such proposals include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

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Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. Please read “—Partnership Status”. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you will likely be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective common unitholder should consider their potential impact on his investment in us. We expect initially to own property or do business in New Mexico, Texas and Colorado. New Mexico and Colorado each impose a personal income tax. Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective common unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state tax, local tax, alternative minimum tax or foreign tax consequences of an investment in us.

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INVESTMENT IN TXO ENERGY PARTNERS BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements (collectively, “Employee Benefit Plans”). Among other things, consideration should be given to:

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whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

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whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

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whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors”; and

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whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans, and IRAs that are not considered part of an Employee Benefit Plan, from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit

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Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

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the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

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the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

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there is no significant investment by “benefit plan investors,” which is generally defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and certain persons, is held by the Employee Benefit Plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first two bullet points above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

Raymond James & Associates, Inc. and Stifel, Nicolaus & Company, Incorporated are acting as representatives of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement dated the date of this prospectus, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the number of our common units set forth opposite its name below.


Underwriters	Number of Common Units

Raymond James & Associates, Inc.		2,350,000

Stifel, Nicolaus & Company, Incorporated		1,500,000

Janney Montgomery Scott LLC		750,000

Capital One Securities, Inc.		400,000


Total		5,000,000

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of our common units (other than those covered by the underwriters’ option to purchase additional common units described below) sold under the underwriting agreement. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated.

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering our common units, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the common units, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officers’ certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Underwriting Discounts and Expenses

The representatives have advised us that the underwriters propose initially to offer our common units to the public at the public offering price set forth on the cover page of this prospectus and to dealers at that price less a concession not in excess of $0.75 per common unit. After this offering, the public offering price, concession or any other term of this offering may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their option to purchase additional common units.


	Per Unit		Without Option		With Option

Public offering price	$	20.00	$	100,000,000	$	115,000,000

Underwriting discount	$	1.40	$	7,000,000	$	8,050,000


Proceeds, before expenses, to us	$	18.60	$	93,000,000	$	106,950,000

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The estimated expenses of this offering payable by us, exclusive of the underwriting discount, are approximately $5,000,000. The underwriting discount includes a structuring fee we will pay to Raymond James & Associates, Inc. equal to 0.75% of the gross proceeds of this offering (including upon exercise of the underwriters’ option to purchase additional common units) for the evaluation, analysis and structuring of the partnership. We will reimburse the underwriters for certain reasonable out-of-pocket expenses (including those related to background checks, blue-sky laws and the review by the Financial Industry Regulatory Authority (“FINRA”) of the terms of sale of the common units offered hereby) not to exceed $50,000 in the aggregate.

Over-Allotment Option

We have granted an option to the underwriters to purchase up to an aggregate of 750,000 additional common units at the public offering price, less the underwriting discount. The underwriters may exercise this option at any time or from time to time for 30 days from the date of this prospectus solely to cover any over-allotments. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional common units proportionate to that underwriter’s initial amount as reflected in the above table.

No Sales of Similar Securities

MSP II, as the holder of common units currently held directly by the Existing Owners, the directors and executive officers of our general partner, and their respective affiliates have agreed with the underwriters not to offer, sell, transfer or otherwise dispose of any common units or any securities convertible into or exercisable or, exchangeable for, exercisable for, or repayable with common units, for a period of 180 days after the date of this prospectus without first obtaining the written consent of the representatives. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly:

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offer, pledge, sell or contract to sell any common units;

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sell any option or contract to purchase any common units;

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purchase any option or contract to sell any common units;

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grant any option, right or warrant for the sale of any common units;

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lend or otherwise dispose of or transfer any common units;

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file or cause to be filed any registration statement related to the common units; or

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enter into any swap hedging, collar or other agreement that can be reasonably expected to transfer, in whole or in part, the economic consequence of ownership of any common units whether any such swap hedging, collar or other agreement is to be settled by delivery of common units or other securities, in cash or otherwise.

This lock-up provision applies to common units and to securities convertible into or exchangeable or exercisable for or repayable with common units. It also applies to common units owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.

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Raymond James & Associates, Inc. and Stifel, Nicolaus & Company, Incorporated may release any of the common units and other securities subject to the lock-up agreements described above in whole or in part subject to the below considerations. When determining whether or not to release common units from lock-up agreements, Raymond James & Associates, Inc. and Stifel, Nicolaus & Company, Incorporated will consider, among other factors, the unitholders’ reasons for requesting the release, the number of common units for which the release is being requested and market conditions at the time. However, Raymond James & Associates, Inc. and Stifel, Nicolaus & Company, Incorporated have informed us that, as of the date of this prospectus, there are no agreements between them and any party that would allow such party to transfer any common units, nor do they have any intention at this time of releasing any of the common units subject to the lock-up agreements, prior to the expiration of the lock-up period.

Listing

We have been approved to list our common units on the NYSE under the symbol “TXO.” In order to meet the requirements for listing on that exchange, the underwriters will undertake to sell a minimum number of our common units to a minimum number of beneficial owners as required by the NYSE.

Determination of Offering Price

Before this offering, there has been no public market for our common units. The public offering price was determined through negotiations between us and the representatives. In addition to prevailing market conditions, the factors to be considered in determining the public offering price are:

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the information set forth in this prospectus and otherwise available to the underwriters;

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the valuation multiples of publicly traded companies that the representatives believe to be comparable to us;

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our financial information;

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the history of, and the prospects for, our company and the industry in which we compete;

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the ability of our management;

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an assessment of our general partner, its past and present operations, and the prospects for, and timing of, our future revenues;

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the present state of our development;

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the above factors in relation to market values and various valuation measures of other companies engaged in activities similar to ours; and

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other factors deemed relevant by the underwriters and us.

An active trading market for our common units may not develop or, if developed, be maintained or be liquid. It is also possible that after this offering our common units will not trade in the public market at or above the public offering price.

The underwriters do not expect to sell more than 5% of the common units in the aggregate to accounts over which they exercise discretionary authority.

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Directed Unit Program

At our request, the underwriters have reserved for sale, at the initial offering price, up to 10% of the common units being offered by this prospectus for sale to our directors, executive officers and certain individuals identified by us. The number of common units available for sale to the general public will be reduced to the extent such persons purchase such reserved common units. Any reserved common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby. Participants in the directed unit program who are employees or affiliates of the Partnership will be required to sign a lock-up agreement with respect to any common units sold to them under the program. Any common units sold in the directed unit program to our directors and executive officers will be subject to the 180-day lock-up agreements described above. We have agreed to indemnify Raymond James & Associates, Inc. and Stifel, Nicolaus & Company, Incorporated and the underwriters in connection with the directed unit program, including for the failure of any participant to pay for its common units.

Price Stabilization, Short Positions and Penalty Bids

Until the distribution of our common units is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our common units. However, the underwriters may engage in transactions that stabilize the price of the common units, such as bids or purchases to peg, fix or maintain that price.

In connection with this offering, the underwriters may purchase and sell our common units in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of our common units than they are required to purchase in this offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ over-allotment option to purchase additional common units described above. The underwriters may close out any covered short position by either exercising their option or purchasing common units in the open market. In determining the source of our common units to close out the covered short position, the underwriters will consider, among other things, the price of our common units available for purchase in the open market as compared to the price at which they may purchase our common units through the option. “Naked” short sales are sales in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing our common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common units in the open market after pricing that could adversely affect investors who purchase in this offering. Stabilizing transactions consist of various bids for or purchases of our common units made by the underwriters in the open market prior to the completion of this offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the underwriters have repurchased common units sold by or for the account of such underwriter in stabilizing or short covering transactions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of our common units. As a result, the price of our common units may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise.

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Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Electronic Distribution

In connection with this offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail. In addition, the underwriters may facilitate Internet distribution for this offering to certain of their Internet subscription customers. The underwriters may allocate a limited number of our common units for sale to their online brokerage customers. An electronic prospectus may be available on the websites maintained by the underwriters. Other than the prospectus set forth in electronic format, the information on the underwriters’ websites is not part of this prospectus.

Other Relationships

In addition, in the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Direct Participation Program Requirements

Because FINRA views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

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VALIDITY OF THE COMMON UNITS

The validity of the common units and certain tax matters will be passed upon for us by Latham & Watkins LLP, Austin, Texas. Certain legal matters in connection with the common units offered by us will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The audited consolidated financial statements of MorningStar Partners, L.P. as of and for the years ended December 31, 2020 and 2021 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, upon the authority of said firm as experts in auditing and accounting.

The audited consolidated statement of revenue and direct operating expenses related to the Vacuum Properties for the period from January 1, 2021 through October 31, 2021 included in this prospectus and elsewhere in the registration statement has been so included in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, upon the authority of said firm as experts in auditing and accounting.

Estimated quantities of proved oil and natural gas reserves of MorningStar Partners, L.P. and the net present value of such reserves as of December 31, 2021 and July 31, 2022 set forth in this prospectus are based upon reserve reports prepared by our internal reservoir engineers and evaluated by Cawley, Gillespie & Associates.

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-l (including the exhibits, schedules and amendments thereto) regarding our common units. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information regarding us and our common units offered in this prospectus, we refer you to the full registration statement, including its exhibits and schedules, filed under the Securities Act. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website. The address of the SEC’s website is www.sec.gov.

As a result of the offering, we will become subject to full information requirements of the Securities Exchange Act of 1934. We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Additionally, we intend to file other periodic reports with the SEC, as required by the Securities Exchange Act of 1934.

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus.

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business strategies;

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the impact of recent acquisitions and our ability to integrate acquired properties and manage related growth;

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our 2023 capital budget;

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ability to replace the reserves we produce through acquisitions and the development of our properties;

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our oil and natural gas reserves;

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general economic conditions, including the effects of a global health crises such as the COVID-19 pandemic;

•

realized oil, natural gas and NGL prices, including the impact of actions relating to oil price and production controls by OPEC, its members and other state-controlled companies;

•

the timing and amount of future production of oil, natural gas and NGL;

•

our hedging strategy and results;

•

our future drilling plans and locations;

•

costs of developing our properties, including our projected drilling and completion costs;

•

costs associated with managing our business, including anticipated production expense and G&A expense;

•

future operating results;

•

cash flow and liquidity;

•

availability of production equipment and oil field labor;

•

capital expenditures;

•

availability and terms of capital;

242

•

tax treatment;

•

marketing, transportation and storage of oil, natural gas and NGL;

•

competition in the oil and natural gas industry;

•

effectiveness of risk management activities;

•

environmental liabilities;

•

governmental regulation and taxation;

•

developments in oil producing and natural gas producing countries; and

•

plans, objectives, expectations and intentions.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and NGL. We disclose important factors that could cause our actual results to differ materially from our expectations as discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statement include:

•

commodity price volatility;

•

the impact of epidemics, outbreaks or other public health events, and the related effects on financial markets, worldwide economic activity and our operations;

•

the impact of COVID-19, and governmental measures related thereto, on global demand for oil and natural gas and on the operations of our business;

•

uncertainties about our estimated oil, natural gas and NGL reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production;

•

the concentration of our operations in the Permian Basin and the San Juan Basin;

•

difficult and adverse conditions in the domestic and global capital and credit markets;

•

lack of transportation and storage capacity as a result of oversupply, government regulations or other factors;

•

lack of availability of drilling and production equipment and services;

•

potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity risks;

•

failure to realize expected value creation from property acquisitions and trades;

•

access to capital and the timing of development expenditures;

243

•

environmental, weather, drilling and other operating risks;

•

regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas;

•

competition in the oil and natural gas industry;

•

loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production;

•

our ability to service our indebtedness;

•

any downgrades in our credit ratings that could negatively impact our cost of and ability to access capital;

•

cost inflation;

•

evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insider or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and

•

risks related to our ability to expand our business, including through the recruitment and retention of qualified personnel.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, our reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

244

INDEX TO FINANCIAL STATEMENTS



Unaudited Pro Forma Financial Statements

Unaudited Pro Forma Balance Sheet as of September 30, 2022			F-4

Unaudited Pro Forma Statements of Operations for the Year Ended December 31, 2021			F-5

Unaudited Pro Forma Statements of Operations for the Nine Months Ended September 30, 2022			F-6

Notes to Unaudited Pro Forma Financial Statements			F-7

MorningStar Partners, L.P.

*Audited Consolidated Financial Statements*

Report of Independent Registered Public Accounting Firm			F-14

Consolidated Balance Sheets as of December 31, 2021 and 2020			F-15

Consolidated Statements of Operations for the Years Ended December 31, 2021 and 2020			F-16

Consolidated Statements of Cash Flows for the Years Ended December 31, 2021 and 2020			F-17

Consolidated Statements of Partners’ Capital for Years Ended December 31, 2021 and 2020			F-18

Notes to Consolidated Financial Statements			F-19

*Unaudited Condensed Financial Statements*

Condensed Balance Sheets as of September 30, 2022 and December 31, 2021			F-44

Condensed Statements of Operations for the Nine Months Ended September 30, 2022 and 2021			F-45

Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2022 and 2021			F-46

Notes to Condensed Financial Statements (Unaudited)			F-48

Vacuum Properties

*Audited Statement of Revenue and Direct Operating Expenses*

Report of Independent Registered Public Accounting Firm			F-60

Statement of Revenue and Direct Operating Expenses for the Period from January 1, 2021 through October 31, 2021			F-62

Notes to Financial Statements			F-63

F-1

TXO ENERGY PARTNERS, L.P.

PRO FORMA FINANCIAL STATEMENTS

(Unaudited)

Introduction

TXO Energy Partners, L.P. (the “Company” or “TXO Energy”) is the new name of MorningStar Partners, L.P. (“MorningStar”). The Company’s business is to engage in oil and natural gas exploration and production. The unaudited pro forma financial statements have been prepared in accordance with Article 11 of Regulation S-X, using assumptions set forth in the notes to the unaudited pro forma financial statements. The following unaudited pro forma financial statements of the Company reflect the historical results of MorningStar, on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on September 30, 2022, for pro forma balance sheet purposes, and on January 1, 2021, for pro forma statement of operations purposes:

•

in the case of the unaudited pro forma statements of operations, the acquisition of producing properties and a gas processing plant in the Permian Basin of New Mexico and CO₂ assets in Colorado from Chevron for approximately $179.3 million (the Vacuum Properties) as described in Note 2 to the historical audited financial statements of MorningStar included elsewhere in this prospectus;

•

the Reorganization Transactions as described in “Prospectus Summary—Reorganization Transactions and Partnership Structure” elsewhere in this prospectus; and

•

the initial public offering of common units and the use of the net proceeds therefrom as described in “Use of Proceeds” (the “Offering”). For purposes of the unaudited pro forma financial statements, the Offering is defined as the issuance and sale to the public of 5,000,000 common units of the Company at an initial public offering price of $20.00 per common unit as contemplated by this prospectus and the application by the Company of the net proceeds from such issuance as described in “Use of Proceeds.” The net proceeds from the sale of the common units are expected to be $88.0 million, net of underwriting discounts of $7.0 million and other offering costs of $5.0 million.

The unaudited pro forma balance sheet of the Company is based on the historical balance sheet of MorningStar as of September 30, 2022 and includes pro forma adjustments to give effect to the described transactions as if they had occurred on September 30, 2022. The unaudited pro forma statements of operations of the Company are based on the audited historical statement of operations of MorningStar for the year ended December 31, 2021, and the unaudited historical statement of operations of MorningStar for the nine months ended September 30, 2022, both having been adjusted to give effect to the described transactions as if they occurred on January 1, 2021.

The pro forma data presented reflect events directly attributable to the described transactions and certain assumptions the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the date indicated or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited financial statements.

F-2

The unaudited pro forma financial statements and related notes are presented for illustrative purposes only. If the Offering and other transactions contemplated herein had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma financial statements. The unaudited pro forma financial statements should not be relied upon as an indication of operating results that the Company would have achieved if the Offering and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma financial statements of operations and should not be relied upon as an indication of the future results the Company will have after the contemplation of the offering and the other transactions contemplated by these unaudited pro forma financial statements.

F-3

TXO ENERGY PARTNERS, L.P.

PRO FORMA BALANCE SHEET

September 30, 2022

(in thousands)


	MorningStar Partners, L.P. Historical			Offering			Pro Forma

ASSETS

Current Assets:

Cash and cash equivalents	$	11,148		$	—		$	11,148

Accounts receivable, net		49,424			—			49,424

Derivative fair value		2,900			—			2,900

Other		10,888			—			10,888


Total Current Assets		74,360			—			74,360


Property and Equipment, at cost—successful efforts method:

Proved properties		1,448,108			—			1,448,108

Unproved properties		18,726			—			18,726

Other		82,017			—			82,017


Total Property and Equipment		1,548,851			—			1,548,851

Accumulated depreciation, depletion and amortization		(734,409	)		—			(734,409	)


Net Property and Equipment		814,442			—			814,442


Other Assets:

Note receivable from related party		7,130			—			7,130

Derivative fair value		187			—			187

Other		5,736			—			5,736


Total Other Assets		13,053			—			13,053


TOTAL ASSETS	$	901,855		$	—		$	901,855


LIABILITIES AND PARTNERS’ CAPITAL

Current Liabilities:

Accounts payable	$	13,031		$	—		$	13,031

Accrued liabilities		36,248			—			36,248

Derivative fair value		39,967			—			39,967

Asset retirement obligation, current portion		2,404			—			2,404


Total Current Liabilities		91,650			—			91,650


Long-term Debt		132,100			(88,000	)(a)		44,100


Other Liabilities:

Asset retirement obligation		110,296			—			110,296

Derivative fair value		17,559			—			17,559

Other liabilities		758			—			758


Total Other Liabilities		128,613			—			128,613


Commitments and Contingencies

Partners’ Capital:

Partners’ capital		549,492			88,000	(a)		637,492


Total Partners’ Capital		549,492			88,000			637,492


TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	901,855		$	—		$	901,855

The accompanying notes are an integral part of these unaudited pro forma financial statements.

F-4

TXO ENERGY PARTNERS, L.P.

Pro Forma Statements of Operations for the Year Ended December 31, 2021

(Unaudited)

(in thousands, except for per unit information)


	MorningStar Partners, L.P. Historical			Vacuum Properties			Offering			Pro Forma
					(b)

REVENUES

Oil and condensate	$	69,971		$	48,215		$	—		$	118,186

Natural gas liquids		27,875			1,935			—			29,810

Gas		130,498			178			—			130,676


Total Revenues		228,344			50,328			—			278,672


EXPENSES

Production		69,256			30,150			—			99,406

Exploration		124			—			—			124

Taxes, transportation and other		58,040			5,062			—			63,102

Depreciation, depletion, and amortization		39,889			7,761	(c)		—			47,650

Accretion of discount in asset retirement obligation		4,670			292	(d)		—			4,962

General and administrative		12,175			—			—			12,175


Total Expenses		184,154			43,265			—			227,419


OPERATING INCOME		44,190			7,063			—			51,253


OTHER INCOME (EXPENSE)

Other income		14,139			3,173			—			17,312

Interest income		16			—			—			16

Interest expense		(5,870	)		1,947	(e)		—			(3,923	)


Other Income		8,285			5,120			—			13,405


NET INCOME	$	52,475		$	12,183		$	—		$	64,658


NET INCOME PER COMMON UNIT(f)

Basic	$	2.10		$	0.49		$	(0.43	)	$	2.16


Diluted	$	2.10		$	0.49		$	(0.47	)	$	2.12


WEIGHTED AVERAGE COMMON UNITS OUTSTANDING(f)

Basic		25,000			25,000			5,000			30,000


Diluted		25,000			25,000			5,045			30,545

The accompanying notes are an integral part of these unaudited pro forma financial statements.

F-5

TXO ENERGY PARTNERS, L.P.

Pro Forma Statements of Operations for the Nine Months Ended September 30, 2022

(Unaudited)

(in thousands, except for per unit information)


	MorningStar Partners, L.P. Historical			Offering			Pro Forma

REVENUES

Oil and condensate	$	120,703		$	—		$	120,703

Natural gas liquids		29,268			—			29,268

Gas		54,067			—			54,067


Total Revenues		204,038			—			204,038


EXPENSES

Production		93,961			—			93,961

Exploration		281			—			281

Taxes, transportation and other		72,993			—			72,993

Depreciation, depletion, and amortization		30,329			—			30,329

Accretion of discount in asset retirement obligation		4,508			—			4,508

General and administrative		572			—			572


Total Expenses		202,644			—			202,644


OPERATING INCOME		1,394			—			1,394


OTHER INCOME (EXPENSE)

Other income		18,677			—			18,677

Interest income		68			—			68

Interest expense		(5,526	)		2,494	(e)		(3,032	)


Other Income		13,219			2,494			15,713


NET INCOME	$	14,613		$	2,494		$	17,107


NET LOSS PER COMMON UNIT(f)

Basic	$	0.58		$	0.50		$	0.57


Diluted	$	0.58		$	0.45		$	0.56


WEIGHTED AVERAGE COMMON UNITS OUTSTANDING(f)

Basic		25,000			5,000			30,000


Diluted		25,000			5,545			30,545

The accompanying notes are an integral part of these unaudited pro forma financial statements.

F-6

TXO ENERGY, LLC

Notes to Pro Forma Financial Statements

1. BASIS OF PRESENTATION, CORPORATE REORGANIZATION AND THE OFFERING

The historical financial information is derived from the financial statements of MorningStar included elsewhere in this prospectus. For purposes of the unaudited pro forma balance sheet, it is assumed that the acquisition of the Vacuum Properties had taken place on September 30, 2022. For purposes of the unaudited pro forma statements of operations, it is assumed all transactions had taken place on January 1, 2021.

Upon closing the Offering, the Company expects to incur direct, incremental general and administrative expenses as a result of being publicly traded, including, but not limited to, costs associated with annual and quarterly reports to unitholders, tax return preparation, independent auditor fees, incremental legal fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. The Company estimates these direct, incremental general and administrative expenses initially will total approximately $3.0 million per year. These direct, incremental general and administrative expenditures are not reflected in the historical financial statements or in the unaudited pro forma financial statements.

Prior to the offering MorningStar Partners, L.P. will be renamed TXO Energy Partners, L.P. in connection with the reorganization transactions as described herein. Following this offering and the corporate reorganization described below, TXO Energy will be a holding company, whose sole material assets will consist of equity interests in operating subsidiaries that own, directly or indirectly, all of our operating assets. After the consummation of the corporate reorganization, TXO Energy GP, LLC (the “General Partner”) will be the sole general partner of the Company. The General Partner will also be responsible for all operational, management and administrative decisions relating to the Company’s business and will consolidate the financial results of the Company and its subsidiaries and as well as its proportionate share of the Cross Timbers Energy joint venture.

Prior to the close of this offering, the following transactions, which we refer to as the reorganization transactions, will occur:

(a) on October 1, 2022, all of MorningStar Partners, L.P.’s outstanding Series 3 preferred units automatically converted into 270,831 common units, and, effective as of October 1, 2022, all of MorningStar Partner, L.P.’s outstanding Series 3 warrants were exercised for 81,249 common units;

(b) the Company will cause the exchange of all of MorningStar Partners, L.P.’s outstanding Series 5 preferred units for 10,235,081 common units;

(c) holders of existing common units (the “Existing Owners”) in the Company will contribute all of the outstanding equity interests into a new parent company, MorningStar Partners II, L.P., a Delaware limited partnership, in exchange for equity interests in MorningStar Partners II, L.P.;

(d) the Company will amend its partnership agreement to, among other things, (i) change its name to “TXO Energy Partners, L.P. and (ii) reflect TXO Energy GP, LLC, a Delaware limited liability company, our new general partner; and

(e) the Company will effectuate the one-for-25.33 Reverse Unit Split.

F-7

2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma financial statements:

(a) Reflects gross proceeds of $100.0 million from the issuance and sale of 5,000,000 common units at an initial public offering price of $20.00 per unit, net of underwriting discounts and commissions of $7.0 million, in the aggregate, and additional estimated expenses related to the Offering of approximately $5.0 million and the use of the net proceeds therefrom as follows:

•

Pay down $88.0 million of outstanding borrowings under the Credit Facility, which were $125.0 million as of September 30, 2022.

(b) Unless otherwise noted, adjustments below in items (c) - (e) reflect the historical statements of revenues and direct operating expenses from the assets acquired and liabilities assumed in the acquisition of the Vacuum Properties, as included elsewhere in this prospectus.

(c) Adjustment reflects additional depreciation, depletion, and amortization expense that would have been incurred with respect to the acquisition of the Vacuum Properties, had such acquisitions occurred on January 1, 2021.

(d) Adjustment reflects additional accretion of discount in asset retirement obligation expense that would have been recorded with respect to the asset retirement obligation assumed in the acquisition of the Vacuum Properties, had such acquisition occurred on January 1, 2021.

(e) Adjustment reflects reduction in interest expense from the use of offering proceeds to pay down debt outstanding, partially offset by additional interest expense that would have been incurred in connection with the borrowing to fund the acquisition of the Vacuum Properties, had each transaction occurred on January 1, 2021, The average interest rate was 4.0% for the year ended December 31, 2021 and 4.8% for the nine months ended September 30, 2022.

F-8

(f) Reflects basic and diluted earnings (loss) per common unit for the issuance of 30 million common units in the Corporate Reorganization and the Offering as shown below:


	Year ended December 31, 2021		Nine months ended September 30, 2022

Basic

Net income (loss)	$	64,658	$	17,107

Common Units issued in the Reorganization Transactions and the Offering		30,000		30,000


Basic earnings (loss) per unit	$	2.16	$	0.57


Diluted

Numerator:

Net income (loss)	$	64,658	$	17,107

Effect of dilutive securities		—		—


Diluted net income (loss) attributable to unitholders	$	64,658	$	17,107


Denominator:

Basic weighted average unit outstanding		30,000		30,000

Effect of dilutive securities		545		545


Diluted weighted average units outstanding		30,545		30,545


Diluted earnings (loss) per unit	$	2.12	$	0.56

3. SUPPLEMENTARY DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS

The following pro forma standardized measure of the discounted net future cash flows and changes applicable to TXO Energy’s proved reserves reflect the effect of Texas state franchise taxes which partnerships are subject to. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of TXO Energy’s proved oil and natural gas properties.

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

F-9

The following table provides a pro forma rollforward of the total proved reserves for the year ended December 31, 2021, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year, as if the acquisition reflected occurred on January 1, 2021.


*Oil (MBbls)*	MorningStar Partners, L.P. Historical			Vacuum Properties			Pro Forma

January 1, 2021		19,604.8			19,042.3			38,647.1

Extensions, additions and discoveries		38.3			—			38.3

Revisions		2,758.8			2,548.5			5,307.3

Production		(1,033.0	)		(746.4	)		(1,779.4	)

Purchase in place		27,236.7			(20,844.4	)		6,392.3


December 31, 2021		48,605.6			—			48,605.6

Proved Developed Reserves

January 1, 2021		9,787.7			12,426.6			22,214.3

December 31, 2021		30,207.9			—			30,207.9

Proved Undeveloped Reserves

January 1, 2021		9,817.1			6,615.7			16,432.8

December 31, 2021		18,397.7			—			18,397.7


*Natural Gas Liquids (MBbls)*	MorningStar Partners, L.P. Historical			Vacuum Properties			Pro Forma

January 1, 2021		8,311.2			3,302.4			11,613.6

Extensions, additions and discoveries		14.5			—			14.5

Revisions		7,277.1			193.1			7,470.2

Production		(1,088.8	)		(48.5	)		(1,137.3	)

Purchase in place		3,513.6			(3,447.0	)		66.6


December 31, 2021		18,027.6			—			18,027.6

Proved Developed Reserves

January 1, 2021		8,311.2			2,737.8			11,049.0

December 31, 2021		17,434.2			—			17,434.2

Proved Undeveloped Reserves

January 1, 2021		—			564.6			564.6

December 31, 2021		593.4			—			593.4

F-10


*Natural Gas (MMcf)*	MorningStar Partners, L.P. Historical			Vacuum Properties			Pro Forma

January 1, 2021		243,172.9			2,316.9			245,489.8

Extensions, additions and discoveries		6,048.3			—			6,048.3

Revisions		152,978.3			294.2			153,272.5

Production		(30,589.7	)		(84.2	)		(30,673.9	)

Purchase in place		7,666.1			(2,526.9	)		5,139.2


December 31, 2021		379,275.9			—			379,275.9

Proved Developed Reserves

January 1, 2021		218,396.9			1,950.2			220,347.1

December 31, 2021		353,214.9			—			353,214.9

Proved Undeveloped Reserves

January 1, 2021		24,776.0			366.7			25,142.7

December 31, 2021		26,061.0			—			26,061.0


*Total (MBoe)*	MorningStar Partners, L.P. Historical			Vacuum Properties			Pro Forma

January 1, 2021		68,444.8			22,730.9			91,175.7

Extensions, additions and discoveries		1,060.9			—			1,060.9

Revisions		35,532.3			2,790.6			38,322.9

Production		(7,220.1	)		(808.9	)		(8,029.0	)

Purchase in place		32,028.0			(24,712.6	)		7,315.4


December 31, 2021		129,845.9			—			129,845.9

Proved Developed Reserves

January 1, 2021		54,498.4			15,489.5			69,987.9

December 31, 2021		106,511.3			—			106,511.3

Proved Undeveloped Reserves

January 1, 2021		13,946.4			7,241.4			21,187.8

December 31, 2021		23,334.6			—			23,334.6

The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2021 (in thousands):


	MorningStar Partners, L.P. Historical			Pro Forma

(in thousands)

Future cash inflows	$	4,468,597			4,468,597

Future costs:

Production		(1,988,988	)		(1,988,988	)

Development		(365,289	)		(365,289	)

Income taxes		(4,110	)		(4,110	)


Future net cash flows		2,110,210			2,110,210

10% annual discount		(1,123,593	)		(1,123,593	)


Standardized measure	$	986,617		$	986,617

F-11

The change in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2021 (in thousands):


	MorningStar Partners, L.P. Historical			Vacuum Properties			Pro Forma

(in thousands)

Standardized measure, beginning of period	$	154,438		$	109,720		$	264,158

Revisions:

Prices and costs		205,842			136,525			342,367

Quantity estimates		76,737			35,757			112,494

Income tax		(1,933	)		—			(1,933	)

Future development costs		2,715			—			2,715

Accretion of discount		15,444			10,972			26,416

Production rates and other		42,064			2,754			44,818


Net revisions		340,869			186,008			526,877

Additions and discoveries		20,272			—			20,272

Production		(93,042	)		(18,289	)		(111,331	)

Development costs		13,973			—			13,973

Purchases in place		550,107			(277,439	)		272,668


Net change		832,179			(109,720	)		722,459


Standardized measure, end of period	$	986,617		$	—		$	986,617

F-12

MORNINGSTAR PARTNERS, L.P.

Consolidated Financial Statements

December 31, 2021 and 2020

F-13

Report of Independent Registered Public Accounting Firm

To the Partners

MorningStar Partners, L.P.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of MorningStar Partners, L.P. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, partners’ capital, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2012.

Dallas, Texas

August 31, 2022

F-14

MORNINGSTAR PARTNERS, L.P.

Consolidated Balance Sheets

(in thousands)


	December 31, 2021			December 31, 2020

ASSETS

Current Assets:

Cash and cash equivalents	$	7,547		$	21,933

Accounts receivable, net		34,124			16,122

Derivative fair value		10,632			—

Other		4,793			3,223


Total Current Assets		57,096			41,278


Property and Equipment, at cost—successful efforts method:

Proved properties		1,376,476			1,183,202

Unproved properties		18,677			18,609

Other		69,254			37,983


Total Property and Equipment		1,464,407			1,239,794

Accumulated depreciation, depletion and amortization		(704,080	)		(666,005	)


Net Property and Equipment		760,327			573,789


Other Assets:

Note receivable from related party		7,132			7,131

Derivative fair value		4,912			—

Other		3,353			1,742


Total Other Assets		15,397			8,873


TOTAL ASSETS	$	832,820		$	623,940


LIABILITIES AND PARTNERS’ CAPITAL

Current Liabilities:

Accounts payable	$	3,965		$	3,660

Accrued liabilities		23,758			14,157

Derivative fair value		6,450			—

Asset retirement obligation, current portion		1,100			1,100


Total Current Liabilities		35,273			18,917


Long-term Debt		152,100			151,252


Other Liabilities:

Asset retirement obligation		103,389			99,570

Derivative fair value		117			—

Other liabilities		582			238


Total Other Liabilities		104,088			99,808


Commitments and Contingencies

Mandatorily redeemable convertible preferred units		—			50,695

Partners’ Capital:

Partners’ capital		541,359			303,268


TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	832,820		$	623,940

See accompanying notes to consolidated financial statements.

F-15

MORNINGSTAR PARTNERS, L.P.

Consolidated Statements of Operations

(in thousands)


	Years ended December 31,
	2021			2020

REVENUES

Oil and condensate	$	69,971		$	59,070

Natural gas liquids		27,875			8,660

Gas		130,498			41,034


Total Revenues		228,344			108,764


EXPENSES

Production		69,256			49,146

Exploration		124			55

Taxes, transportation and other		58,040			27,509

Depreciation, depletion, and amortization		39,889			42,322

Impairment		—			134,097

Accretion of discount in asset retirement obligation		4,670			3,940

General and administrative		12,175			6,995


Total Expenses		184,154			264,064


OPERATING INCOME (LOSS)		44,190			(155,300	)


OTHER INCOME (EXPENSE)

Other income		14,139			72

Interest income		16			194

Interest expense		(5,870	)		(8,204	)


Other Income (Expense)		8,285			(7,938	)


NET INCOME (LOSS)	$	52,475		$	(163,238	)

See accompanying notes to consolidated financial statements.

F-16

MORNINGSTAR PARTNERS, L.P.

Consolidated Statements of Cash Flows

(in thousands)


	Years ended December 31,
	2021			2020

OPERATING ACTIVITIES

Net income (loss)	$	52,475		$	(163,238	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities, net of effects of assets acquired and liabilities assumed:

Depreciation, depletion, and amortization		39,889			42,322

Impairment		—			134,097

Accretion of discount in asset retirement obligation		4,670			3,940

Derivative fair value (gain) loss		(8,977	)		(23,305	)

Net cash received from (paid to) counterparties		—			26,192

Non-cash gain on forgiveness of debt		(9,152	)		—

Non-cash incentive compensation		2,400			4,227

Other non-cash items		(585	)		886

Changes in operating assets and liabilities(a)		(6,994	)		(6,157	)


Cash Provided by Operating Activities		73,726			18,964


INVESTING ACTIVITIES

Proved property acquisitions		(185,931	)		(10,961	)

Development costs		(8,372	)		(4,989	)

Unproved property acquisitions		(67	)		(307	)

Other property additions		(33,431	)		(461	)


Cash Used in Investing Activities		(227,801	)		(16,718	)


FINANCING ACTIVITIES

Proceeds from long-term debt		1,437,000			1,932,152

Payments on long-term debt		(1,427,000	)		(1,968,000	)

Proceeds from temporary equity investment		—			50,695

Proceeds from permanent equity investment		132,660			—

Debt issuance costs		(2,832	)		(709	)

Payments on vesting of restricted units		—			(40	)

Distributions		(139	)		(31	)


Cash Provided by Financing Activities		139,689			14,067


(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(14,386	)		16,313

Cash and Cash Equivalents, beginning of period		21,933			5,620


Cash and Cash Equivalents, end of period	$	7,547		$	21,933


(a) Changes in Operating Assets and Liabilities

Accounts receivable	$	(14,811	)	$	(8,103	)

Other assets		(1,571	)		(240	)

Aid-in-construction asset		—			(238	)

Current liabilities		10,028			3,224

Other operating liabilities		(640	)		(800	)


	$	(6,994	)	$	(6,157	)

See accompanying notes to consolidated financial statements.

F-17

MORNINGSTAR PARTNERS, L.P.

Consolidated Statements of Partners’ Capital

(in thousands)


	Series 3 Preferred		Series 4 Preferred			Series 5 Preferred		Common			Total

Balances, December 31, 2019	$	34,295	$	—		$	—	$	428,055		$	462,350

Net loss		—		—			—		(163,238	)		(163,238	)

Increase in partners’ equity from in-kind distributions		—		—			—		1,585			1,585

In-kind distributions		—		—			—		(1,585	)		(1,585	)

Expensing of unit awards		—		—			—		4,227			4,227

Withholding tax paid on vesting restricted units		—		—			—		(40	)		(40	)

Distributions		—		—			—		(31	)		(31	)


Balances, December 31, 2020	$	34,295	$	—		$	—	$	268,973		$	303,268

Net income		—		—			—		52,475			52,475

Increase in partners’ equity from in-kind distributions		—		—			—		8,248			8,248

In-kind distributions		—		—			—		(8,248	)		(8,248	)

Expensing of unit awards		—		—			—		2,400			2,400

Contributions of cash		—		—			132,660		—			132,660

Distributions		—		—			—		(139	)		(139	)

Accretion of original issue discount on temporary equity		—		(2,668	)		—		—			(2,668	)

Conversion of temporary equity to permanent equity		—		53,363			—		—			53,363

Gain (loss) from the exchange of Series 4 preferred units		—		22,719			—		(22,719	)		—

Exchange of Series 4 preferred units to Series 5 preferred units		—		(73,414	)		73,414		—			—


Balances, December 31, 2021	$	34,295	$	—		$	206,074	$	300,990		$	541,359

See accompanying notes to consolidated financial statements.

F-18

MORNINGSTAR PARTNERS, L.P.

Notes to Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

MorningStar Partners, L.P. (MorningStar or the Company), is an independent oil and gas company that was formed as a Delaware limited partnership in January 2012 (with an effective inception of operations at January 18, 2012). The operations of MorningStar are governed by the provisions of the partnership agreement, as amended, executed by the general partner, MorningStar Oil & Gas, LLC (MSOG) and the limited partners. MSOG is the manager of MorningStar and is paid a quarterly management fee equal to 1% of revenue, less production expense, severance taxes and other deductions, at the discretion of the MorningStar board of directors. Under the amended partnership agreement, this management fee is currently suspended. MorningStar is governed by a board of directors made up of five officers and five outside investors. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s partners. Pursuant to applicable provisions of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and the limited partnership agreement, the partners have no liability for the debts, obligations and liabilities of MorningStar, except as expressly required in the limited partnership agreement or the Delaware Act. MorningStar will remain in existence unless and until dissolved in accordance with the terms of the partnership agreement.

MorningStar’s assets include its investment in an unincorporated joint venture. MorningStar owns 50% of the joint venture, and MorningStar is the manager of the joint venture. The joint venture is governed by a Member Management Committee (MMC) and is comprised of six representatives, three from each group, with each group having one voting member. All matters that come before the MMC require the unanimous consent of the voting members. On the last day of each calendar quarter, the joint venture distributes all excess cash to the members based on their ownership percentage of 50% each, except for earnings from the note receivable which is owned 5% by MorningStar. The joint venture’s properties are located primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.

MorningStar also has a wholly-owned subsidiary, MorningStar Operating, LLC which owns oil and gas assets primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.

In accordance with oil and gas accounting guidance, we account for our undivided interest in our investment in the joint venture using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of the joint venture. As discussed above, we own 50% of the oil and gas assets, liabilities, revenues and expenses, but we only own 5% of the note receivable from related party and related interest income.

In February 2015, we entered into a Limited Liability Company Agreement, as amended, (LLC Agreement) with EnCap Energy Capital Fund IX, L.P. and EnCap Energy Capital Fund X, L.P. (EnCap entities) to form Southland Royalty Company LLC (Southland LLC). On January 27, 2020, Southland filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (January 2020 Reorganization Filing). As a result, we deconsolidated our remaining investment in Southland as of December 31, 2019. However, we remained involved with the management and wind down of Southland until Southland exited from bankruptcy in June 2021.

F-19

The accompanying consolidated financial statements include the financial statements of MorningStar, its wholly-owned subsidiaries and our undivided interests in the joint venture. All significant intercompany balances and transactions have been eliminated in consolidation.

Basis of Presentation

The accounts of MorningStar are presented in the accompanying financial statements. These financial statements have been prepared in accordance with U.S. GAAP.

Liquidity

Our primary sources of liquidity are cash provided by operating activities, borrowings under our credit facility and equity raised from partners. Short-term liquidity needs are provided by borrowings under our credit facility. We believe that we have a sufficient combination of resources and operating flexibility to ensure that we remain in compliance with our future debt covenants for all of our outstanding debt for at least the next 12 months from the date of issuance of these financial statements. See Note 4.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

•

estimates of proved reserves and related estimates of the present value of future revenues;

•

the recoverability of oil and gas properties;

•

estimates of revenue earned but not yet received;

•

asset retirement obligations; and

•

legal and environmental risks and exposure.

Property and Equipment

We follow the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. We generally pursue acquisition and development of proved reserves as opposed to exploration activities. All of the proved property costs reflected in the accompanying balance sheet are from MorningStar, our wholly-owned subsidiary, MorningStar Operating, LLC, and our 50% share of the joint venture’s proved properties as of December 31, 2021 and 2020. Proved properties balances include costs of $2.4 million at December 31, 2021 and $5.9 million at December 31, 2020 related to wells in process of drilling. Successful drill well costs are transferred to proved properties generally within one month of the well completion date.

F-20

Depreciation, depletion, and amortization (DD&A) of proved producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. Other property and equipment is generally depreciated using the straight-line method over estimated useful lives which range from three to seven years, except for the gas processing plant which is being depreciated over an estimated useful life of 14 years. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.

If conditions indicate that proved properties may be impaired, the carrying value of property is compared to management’s future estimated pre-tax undiscounted cash flow from properties generally aggregated on a field-level basis. If impairment is necessary, the asset carrying value is written down to fair value, typically a discounted present value of estimated future cash flows. Cash flow pricing estimates are based on estimated reserves and production information and pricing assumptions that management believes are reasonable. During the year end ended December 31, 2021, we did not recognize an impairment of long-lived assets. During the year end ended December 31, 2020, we recognized an impairment of long-lived assets of $133.2 million for our assets in the New Mexico Permian Basin, $0.2 million for our assets in East Texas and $0.7 million on our unproved properties primarily in the Texas Permian Basin primarily due to a lower net commodity price environment for some of our oil and natural gas assets.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion, and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized in the current period.

Asset Retirement Obligation

If the fair value for asset retirement obligation can be reasonably estimated, the liability is recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. The retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to proved properties on the balance sheet. Periodic accretion of discount of the estimated liability is recorded as an expense in the statements of operations. See Note 8.

Cash and Cash Equivalents

Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less.

Fair Value of Financial Instruments

Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value.

F-21

Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:

Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

Income Taxes

MorningStar is a limited partnership treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Company passed through to the partners. As such, with the exception of the state of Texas, we are not a taxable entity, we do not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for our operations, except as described below.

Limited partnerships are subject to state income taxes in Texas. Due to immateriality, income taxes related to the Texas margin tax have been included in general and administrative expenses on the statement of operations and no deferred tax amounts were calculated.

Derivatives

We do not designate these derivative contracts as cash flow hedges. Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil and gas revenues. Settlements of derivatives are included in cash flows from operating activities.

Revenue Recognition

Oil, gas and natural gas liquids revenues are recognized upon the satisfaction of the performance obligation which occurs at the point in time when control of the product transfers to a customer, in an amount that reflects the consideration to which the Company expects to be entitled in exchange for the product. See Note 13 for further discussion.

Loss Contingencies

When management determines that it is probable that an asset has been impaired or a liability has been incurred, we accrue our best estimate of the loss if it can be reasonably estimated. Any legal costs related to litigation are expensed as incurred.

F-22

Unit-Based Compensation

We recognize compensation related to all unit-based awards in the financial statements based on their estimated grant-date fair value. We estimate expected forfeitures and we recognize compensation expense only for those awards expected to vest. Compensation expense is amortized on a straight-line basis over the estimated service period. All compensation is recognized by the time the award vests. See Note 12.

Significant Purchasers

We evaluated how MorningStar is organized and managed and have identified only one operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. All of our assets are located in the United States, and all revenues are attributable to United States customers.

Our production is sold to various purchasers, based on their credit rating and the location of our production. Sales to three purchasers for the year ended December 31, 2021 and sales to two purchasers for the year ended December 31, 2020, as shown in the table below, were greater than 10% of total revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from these significant purchasers.


Customer	2021			2020

Customer A		19	%		25	%

Customer B		12	%		17	%

Customer C		11	%		—	%

2. Establishment of Joint Ventures and Acquisitions

Joint Venture

On October 1, 2012, our joint venture partner contributed producing properties with a fair value of $805.2 million and MorningStar contributed cash of $425.7 million to the joint venture. In a second transaction, our joint venture partner contributed additional producing properties with a fair value of $48.0 million and MorningStar contributed additional cash of $25.3 million. The contributed cash, less $4.0 million retained for working capital purposes, was loaned to an offshore subsidiary of our joint venture partner. See Note 5.

Since that time, MorningStar has contributed $467.5 million of cash and $107.0 million of proved properties, while our joint venture partner has contributed $663.6 million of proved property.

Acquisitions

In August 2022, MorningStar completed the acquisition of additional interest in our producing properties and gas processing plant in the Permian Basin of New Mexico from Vendera Resources for approximately $52.6 million. Our purchase price allocation included $49.6 million to proved properties, $9.8 million to other properties, $3.6 million as a reduction to other current assets, $0.1 million to other current liabilities and $3.1 million to asset retirement obligation. The acquisition was funded by borrowings from our credit facility.

F-23

In February 2022, MorningStar completed the acquisition of producing properties in the Permian Basin of Texas from Kaiser Francis for approximately $3.8 million. Our purchase price allocation included $4.0 million to proved properties and $0.2 million to asset retirement obligation. The acquisition was funded by cash on hand.

In December 2021, MorningStar completed the acquisition of producing properties in the Permian Basin of Texas from Chevron for approximately $43.8 million. Our purchase price allocation included $47.2 million to proved properties and $3.4 million to asset retirement obligation. The acquisition was funded by cash on hand and borrowings from our credit facility. The acquisition is subject to typical post-closing adjustments.

In November 2021, MorningStar completed the acquisition of producing properties and a gas processing plant in the Permian Basin of New Mexico and CO₂ assets in Colorado from Chevron for approximately $175.4 million. Our purchase price allocation included $145.2 million to proved properties, $33.3 million to other properties, $4.3 million to other current assets and $7.4 million to asset retirement obligation. The acquisition was funded by cash on hand from the October 2021 capital raise (see Note 11) and borrowings from our credit facility. The acquisition is subject to typical post-closing adjustments. In the 2021 statement of operations, we recorded $15.0 million of revenues and income of $2.8 million from this acquisition.

In June 2020, MorningStar completed the acquisition of producing properties in the San Juan Basin of New Mexico and Colorado from Southland Royalty for approximately $10.2 million. Our purchase price allocation included $69.0 million to proved properties, $54.6 million to asset retirement obligation, $4.0 million to other current liabilities and $0.2 million to other liabilities. The acquisition was funded by cash on hand.

During 2020, we completed multiple acquisitions of producing properties in the Permian Basin of Texas and New Mexico for $0.7 million. We allocated $ $0.7 million to proved property. These were funded by cash on hand.

Pro forma financial information

The following pro forma financial information represents the results for the Company and the properties acquired in November 2021 in the Permian Basin of New Mexico and CO2 assets in Colorado from Chevron as if the acquisition and the required financing had occurred on January 1, 2020.

For the pro forma year ended December 31, 2021, pro forma revenues were $278.7 million and pro forma net income was $61.4 million. For the purposes of the pro forma, it was assumed that $40.0 million of the Company’s revolving credit facility was used to finance the acquisition resulting in additional interest expense of $1.3 million. The pro forma financial information includes the effects of adjustments for depreciation, depletion, and amortization of $7.8 million, and accretion of asset retirement obligations expense of $0.3 million.

For the pro forma year ended December 31, 2020, pro forma revenues were $149.2 million and pro forma net loss was $159.0 million. For the purposes of the pro forma, it was assumed that $40.0 million of the Company’s revolving credit facility was used to finance the acquisition resulting in additional interest expense of $1.6 million. The pro forma financial information includes the effects of adjustments for depreciation, depletion, and amortization of $11.0 million, and accretion of asset retirement obligations expense of $0.4 million.

F-24

The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

3. Related Party Transactions

We earned management fees from the joint venture of $6.1 million for the year ended December 31, 2021, and $6.4 million for the year ended December 31, 2020. As of December 31, 2021, we had a note receivable from related party outstanding with a highly-rated, offshore subsidiary of our joint venture partner (Note 5). On September 30, 2016, MorningStar entered in a loan agreement with the joint venture (Note 4).

We earned management fees from Southland Royalty Company of $5.0 million for the year ended December 31, 2021 and $15.5 million for the year ended December 31, 2020.

Since the purpose of the management fees is to share costs between the various entities, the management fees from the joint venture and Southland are included as a reduction of general and administrative expenses in our statements of operations.

We occupy a building owned by MorningStar Capital LLC, a limited liability company owned by one of our limited partners. In lieu of paying rent, we paid property taxes and paid for repairs and maintenance on behalf of MorningStar Capital of $0.9 million in 2021 and $1.5 million in 2020.

We did not pay management fees to our general partner, MSOG, in 2021 and 2020.

4. Debt


(in thousands)	December 31, 2021		December 31, 2020

MorningStar Partners Credit Facility, 3.6% at December 31, 2020	$	—	$	137,000

November 2021MorningStar Partners Credit Facility, at 4.0% at December 31, 2021	$	145,000	$	—

MorningStar Partners Loan, 3.4% at December 31, 2021 and 3.4% at December 31, 2020	$	7,100	$	7,100

MorningStar Partners Paycheck Protection Program Loan, 1.0% at December 31, 2020	$	—	$	7,152


Total Long-term Debt	$	152,100	$	151,252

MorningStar Partners Credit Facility

On October 1, 2012, we entered into a five-year, $350 million senior secured credit facility with certain commercial banks. The facility had a maturity date of October 1, 2022. On July 1, 2013, we entered into an amendment to the senior secured credit facility to increase the commitment to $750 million. The amended facility was limited to the lesser of: (i) the then effective borrowing base or (ii) the maximum commitment amount. We had the option, with bank approval, to increase the commitment up to $1 billion. On April 29, 2020, we entered into the thirteenth amendment to the agreement and redetermined the borrowing base to $115 million. As a

F-25

result of the redetermination, there was a borrowing base deficiency of $65 million. A payment of at least $35 million was due no later than June 1, 2020 and all covenants were waived until March 2021. The remainder of the deficiency was not required to be cured. On June 1, 2020, we entered into the fourteenth amendment to the agreement to extend the due date of the borrowing base deficiency payment to July 31, 2020. On July 31, 2020, we entered into the fifteenth amendment to the agreement to not count the new Series 4 Preferred Units (Note 11) as debt and to allow the additional proceeds from the July 2020 capital raise to be retained by MorningStar. On November 1, 2021, we paid off the $100 million outstanding on this credit facility and replaced it with a new credit facility (See November 2021 MorningStar Partners Credit Facility) Prior to the pay off, we used the MorningStar Partners Credit Facility for general corporate purposes. In connection with entering into the credit facility and amendments, as of December 31, 2020, we had incurred financing fees and expenses of approximately $10.9 million before accumulated amortization of $9.8 million. The remaining costs were fully expensed when the facility was paid off in November 2021. Such amortized expenses are recorded as interest expense on the statements of operations. The weighted average interest rate on credit facility borrowings was 3.4% in 2021 and 3.8% in 2020.

November 2021 MorningStar Partners Credit Facility

On November 1, 2021, we entered into a new four-year, $165 million senior secured credit facility with certain commercial banks. The facility has a maturity date of November 1, 2025. We use the facility for general corporate purposes. In connection with entering into the credit facility, as of December 31, 2021, we incurred financing fees and expenses of approximately $2.7 million before accumulated amortization of $0.1 million. These costs are being amortized over the life of the credit facility. Such amortized expenses are recorded as interest expense on the statements of operations.

Redetermination of the borrowing base under the credit facility, is based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in March and September, as well as upon requested interim redeterminations, by the lenders at their sole discretion. We also have the right to request additional borrowing base redeterminations each year at our discretion. Significant declines in commodity prices may result in a decrease in the borrowing base. These borrowing base declines can be offset by any commodity price hedges we enter. Our obligations under the credit facility are secured by all assets of the Company, including without limitation (i) our interest in the joint venture, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by MorningStar or its wholly-owned subsidiaries. We are required to maintain (i) a current ratio greater than 1.0 and current assets shall include availability under the credit facility but shall exclude the fair value of derivative instruments and any advances under the facility and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. The total indebtedness-to-EBITDAX calculation is limited to the joint venture’s EBITDAX that has been paid in cash to MorningStar through distributions, MorningStar Operating’s EBITDAX results and realized hedge gains less realized hedge losses and the consolidated expenses of MorningStar and its subsidiaries. EBITDAX means net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments.

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Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The weighted average interest rate on credit facility borrowings was 4.0% in 2021.

MorningStar Partners Loan

On September 30, 2016, MorningStar entered into a $27.1 million loan agreement with the joint venture. The proceeds for the loan were taken from the cash held by the offshore subsidiary of Exxon Mobil Corporation and the loan was assigned to the offshore subsidiary (Note 5). The loan matures on January 31, 2026, but is automatically extended should our credit facility be extended. In all instances, this loan will mature ninety-one days after the maturity of the current Morningstar credit facility. Interest on the loan is the lesser of (a) London Interbank Offered Rate (“LIBOR”) plus three and one-quarter of one percent (3.25%) per annum, adjusted monthly or (b) the highest rate permitted by applicable law. The note is unsecured, but we are required to stay in compliance with terms of our current credit facility. The weighted average interest rate on loan was 3.4% in 2021 and 4.0% in 2020.

On September 30, 2020, $20.0 million was distributed to MorningStar Partners from the note receivable. This distribution was used by MorningStar Partners to pay down the outstanding loan with the joint venture.

Paycheck Protection Program Loans

On April 13, 2020, we received a loan of approximately $7.2 million under the US Government’s Paycheck Protection Program from the Small Business Administration (“SBA”). Under the terms of the loan, it was required to be repaid beginning November 13, 2020 in equal installments until April 13, 2022, unless we qualified for loan forgiveness. The loan bore interest at a rate of 1% per annum. In August 2020, we sent in our loan forgiveness application for the entire loan amount. As a result of filing the application, we did not make any payments on the loan, nor did we accrue any interest on the loan in 2020. On June 14, 2021 we received notice that the loan was forgiven in full. We recorded this loan forgiveness as other income on the statements of operations.

On January 27, 2021, we received a second loan for $2.0 million under an extension of the US Government’s Paycheck Protection Program from the SBA. On July 2, 2021 we received notice that the loan was forgiven in full. We recorded this loan forgiveness as other income on the statements of operations.

5. Note Receivable from Related Party

As of December 31, 2021, we, through our 5% ownership interest in investment assets at the joint venture, had a note receivable totaling $7.1 million outstanding with a highly-rated, offshore subsidiary of our joint venture partner. Under the terms of the agreement, there is no stated maturity date and, the joint venture may demand repayment of all or any portion of the outstanding balance on two business days’ notice. Interest is earned based on the one-month LIBOR rate and is paid monthly. Interest income totaled less than $0.1 million in 2021 and $0.2 million in 2020.

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On September 30, 2020, $20.0 million was distributed to MorningStar Partners from the note receivable. This distribution was used by MorningStar Partners to pay down the loan outstanding with the joint venture. See Note 4.

The note receivable is treated as a non-current asset, since the joint venture does not have any intention of demanding repayment of all or any portion of the outstanding balance at this time. Repayment would require the approval of the joint venture MMC.

6. Commitments and Contingencies

From time to time, the Company is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company.

To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Commodity Commitments

During 2021 and 2020, we entered into futures contracts and swap agreements that effectively fixed natural gas and crude oil prices. See Note 10.

7. Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of asset retirement obligation activity for the years ended December 31, 2021 and 2020:


	(in thousands)

	2021			2020

Asset retirement obligation, January 1	$	100,670		$	49,392

Revisions in the estimated cash flows(1)		(7,157	)		(6,727	)

Liability incurred upon acquiring and drilling wells		10,741			54,902

Liability settled upon sale of wells		(3,580	)		—

Liability settled upon plugging and abandoning wells		(855	)		(837	)

Accretion of discount expense		4,670			3,940


Asset retirement obligation, December 31		104,489			100,670

Less current portion		(1,100	)		(1,100	)


Asset retirement obligation, long term	$	103,389		$	99,570

(1)	Revisions in the estimated cash flows for the years ended December 31, 2021 and 2020 are primarily the result of revised cost estimates.

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8. Fair Value

We use commodity-based and financial derivative contracts to manage exposures to commodity price. We do not hold or issue derivative financial instruments for speculative or trading purposes. We periodically enter into futures contracts, costless collars, energy swaps, swaptions and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales (Note 10).

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 2021 and 2020. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	Asset (Liability)
	December 31, 2021						December 31, 2020
	Carrying			Fair			Carrying			Fair
(in thousands)	Amount			Value			Amount			Value

Note receivable from related party	$	7,132		$	7,132		$	7,131		$	7,131


Long-term debt	$	(152,100	)	$	(152,100	)	$	(151,252	)	$	(151,252	)


Derivative asset	$	15,544		$	15,544		$	—		$	—


Derivative liability	$	(6,567	)	$	(6,567	)	$	—		$	—

The fair value of our note receivable from related party approximates the carrying amount because the interest rate is based on current market interest rates and can be called upon two business days’ notice (Note 5). The fair value of our long-term debt approximates the carrying amount because the interest rate is reset periodically at then current market rates (Note 4).

The fair value of our note receivable from related party (Note 5), net derivative asset (Note 10) and our long-term debt (Note 4) is measured using Level II inputs, and are determined by either market prices on an active market for similar assets or other market-corroborated prices. Counterparty credit risk is considered when determining the fair value of our notes receivable and net derivative asset. Since our counterparty is highly rated, the fair value of our note receivable from related party does not require an adjustment to account for the risk of nonperformance by the counterparty, however, an adjustment for counterparty credit risk has been applied to the net derivative asset.

The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.


	Fair Value Measurements
	December 31, 2021					December 31, 2020
	Significant					Significant
	Other			Significant		Other			Significant
	Observable			Unobservable		Observable			Unobservable
	Inputs			Inputs		Inputs			Inputs
(in thousands)	(Level 2)			(Level 3)		(Level 2)			(Level 3)

Note receivable from related party	$	7,132		$	—	$	7,131		$	—


Long-term debt	$	(152,100	)	$	—	$	(151,252	)	$	—


Derivative asset	$	15,544		$	—	$	—		$	—


Derivative liability	$	(6,577	)	$	—	$	—		$	—

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable and are based upon Level 3 inputs. These assets and liabilities can include assets and liabilities acquired in a business combination, proved and unproved natural gas properties, asset retirement obligations and other long-lived assets that are written down to fair value when they are impaired.

We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We review our oil and natural gas properties by asset group. The estimated future net cash flows are based upon the underlying reserves and anticipated future pricing. An impairment loss is recognized if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of a particular asset, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of such assets. The fair value of the proved properties is measured based on the income approach, which incorporates a number of assumptions involving expectations of future product prices, which the Company bases on the forward-price curves, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk adjusted discount rate of 10%. These inputs are categorized as Level 3 in the fair value hierarchy. We recognized an impairment of $0.0 million in the year ended December 31, 2021 and $134.1 million in the year ended December 31, 2020.

Commodity Price Hedging Instruments

We periodically enter into futures contracts, energy swaps, swaptions, collars and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. See Note 10.

The fair value of our derivatives contracts consists of the following:


	Asset Derivatives				Liability Derivatives
	December 31,				December 31,
(in thousands)	2021		2020		2021			2020

Derivatives not designated as hedging instruments:

Crude oil futures and differential swaps	$	2,342	$	—	$	(1,996	)	$	—

Natural gas liquids futures	$	685	$	—	$	(204	)	$	—

Natural gas futures, collars and basis swaps	$	12,517	$	—	$	(4,367	)	$	—


Total	$	15,544	$	—	$	(6,567	)	$	—

Derivative fair value (gain) loss, included as part of the related revenue line on the consolidated statements of operations, comprises the following realized and unrealized components:


(in thousands)	2021			2020

Net cash (received from) paid to counterparties	$	—		$	(26,192	)

Non-cash change in derivative fair value	$	(8,977	)	$	2,887


Derivative fair value (gain) loss	$	(8,977	)	$	(23,305	)

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Concentrations of Credit Risk

Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss from the other companies. Including the bank that issued the letter of credit, we currently have greater concentrations of credit with several investment-grade (BBB- or better) rated companies.

9. Commodity Sales Commitments

Our policy is to consider hedging a portion of our production at commodity prices the general partner deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, the general partner may enter into hedging agreements because of the benefits of predictable, stable cash flows.

Crude Oil

We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 9.


			Weighted Average
			NYMEX
Production Period	Bbls per Day		Price per Bbl

January 2022—December 2022		3,500	$	71.28

January 2023—December 2023		2,500	$	68.87

January 2024—June 2024		2,000	$	63.27

The price we receive for our oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered sell basis swap agreements that effectively fix the basis adjustment for the West Texas Midlands delivery location for the production and periods shown below.


			Weighted Average
			NYMEX
Production Period	Bbls per Day		Price per Bbl(a)

January 2022—December 2022		3,000	$	0.55

(a)	Increases to NYMEX oil price for delivery location

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The price we receive for our oil production is generally different than the NYMEX price because of changes in the roll component of the NYMEX price due to the timing of when the monthly NYMEX price is set. We have entered sell basis swap agreements that effectively fix the roll component of the NYMEX price for the production and periods shown below.


			Weighted Average
			NYMEX
Production Period	Bbls per Day		Price per Bbl(a)

January 2022—December 2022		5,000	$	0.50

January 2023—December 2023		1,000	$	0.68

(a)	Increases to NYMEX oil price for roll component

Net settlement gains on oil futures and sell basis swap contracts increased oil revenues by $27.2 million in 2020. An unrealized gain in 2021 and an unrealized loss in 2020 to record the fair value of derivative contracts increased oil revenues by $0.3 million in 2021 and decreased oil revenues by $3.0 million in 2020.

Natural Gas Liquids

We have entered into natural gas liquids futures contracts and swap agreements for certain components—ethane and propane—that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 9.


			Weighted Average

			NGL OPIS

Production Period	Gallons per Day		Price per Gallon
Ethane

January 2022—December 2022		63,000	$	0.33

January 2023—December 2023		63,000	$	0.27

January 2024—June 2024		63,000	$	0.23

Propane

January 2022—December 2022		31,500	$	1.01

An unrealized gain in 2021 to record the fair value of derivative contracts increased NGL revenues by $0.5 million in 2021.

Natural Gas

We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 9.


			Weighted Average

			NYMEX

Production Period	MMBtu per Day		Price per MMBtu

January 2022—December 2022		45,000	$	4.23

January 2023—December 2023		35,000	$	3.51

January 2024—June 2024		30,000	$	3.26

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We have also entered into gas collars that set a ceiling and floor price for the production and periods shown below.


			Weighted Average

			NYMEX Price per MMBtu

Production Period	MMBtu per Day		Floor		Ceiling

January 2022—December 2022		15,000	$	3.50	$	5.85

The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered sell basis swap agreements that effectively fix the basis adjustment for the San Juan Basin delivery location for the production and periods shown below.


			Weighted Average

			Sell Basis

Production Period	MMBtu per Day		Price per MMBtu(a)

January 2022—December 2022		70,000	$	0.22

January 2023—December 2023		20,000	$	0.15

(a)	Reductions to NYMEX gas price for delivery location

Net settlement losses on gas futures and sell basis swap contracts decreased gas revenues by $1.0 million in 2020. An unrealized gain to record the fair value of derivative contracts increased gas revenues by $8.2 million in 2021 and $0.1 million in 2020.

10. Partners’ Capital

Partners’ Units

Under the terms of the amended partnership agreement, there are two classes of units, Common Units and Preferred Units. The general partner establishes the number of authorized units and as of December 31, 2021, the general partner has not established the authorized number of Common Units.

In conjunction with an offering in August 2019, we created a new class of Preferred Units, Series 3 Preferred Units. Each Series 3 Preferred Unit cost $25 per unit and also included warrants to purchase an additional 1.5 common units for $1. The effect of the warrant is to provide 6.5 common units at a total cost of $26 or $4 per unit. The Series 3 Preferred Units will receive semi-annual distributions in the amount of $0.625 per unit. A holder of Series 3 Preferred Units will receive in-kind distributions of Common Units for their Series 3 Preferred Units. The number of in-kind Common Units will accrue at a conversion price of $1.80 per unit. The semi-annual distributions are guaranteed and are to be paid in April and October. The Series 3 Preferred Units automatically convert to five Common Units no later than October 1, 2022 and the warrant is exercisable until October 1, 2023. The holder of Series 3 Preferred Units is entitled to cast the number of votes that the holder would be entitled to cast if the applicable Series 3 Preferred Unit was fully converted into Common Units.

In conjunction with an offering in July 2020, we created an additional class of Preferred Units, Series 4 Preferred Units. Each Series 4 Preferred Unit was issued at $95,000 per unit (an original issue discount of $5,000 per unit) and also included warrants equal to, in the aggregate, 20% non-dilutable common units, at the time of exercise. These warrants had a term of five years from the date of closing and an exercise price of $0.01 each. If holders of a majority of the warrants

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elected to exercise the warrants, then all warrants were required to be exercised at the same time. There was also a group of backstop investors that provided a minimum amount of capital of a least $35 million. These backstop investors received an arrangement fee in the form of warrants to purchase common units for $0.01 per common unit, with warrants equal to, in the aggregate, 10% non-dilutable common units at the time of exercise. These warrants had a term of 15 years. The Series 4 Preferred Units received a semi-annual payment of 12% paid-in-kind units at $0.20 per unit or 10% cash pay as permitted. The Company could call the Series 4 Preferred Units at any time and at a cost of $100,000 per unit plus any accrued dividends at such date. However, if we called the Series 4 Preferred Units on or prior to the second anniversary of the offering, we were required to pay $130,000 per unit. Beginning August 1, 2025, the Series 4 Preferred Units could be put back to us for repayment at a cost of $100,000 per unit plus any accrued dividends at such date. As a result of this offering, we issued 533.63 units for total proceeds of $50.4 million net of $0.3 million of offering costs. The proceeds were used to pay down $35 million on our Credit Facility (see Note 4) and the remainder was retained for future cash needs.

In conjunction with an offering in October 2021, we created an additional class of Preferred Units, Series 5 Preferred Units. Each Series 5 Preferred Unit was issued at $100,000 per unit. The Series 5 Preferred Units receive a semi-annual payment of 6.25% paid-in cash. The Series 5 Preferred Units automatically convert to Common Units at a rate of $0.80 per unit no later than October 15, 2024. In conjunction with this offering, all Series 4 Preferred Units were exchanged into Series 5 Preferred Units at a rate of 1.4 Series 5 Preferred Units for each Series 4 Preferred Unit. Additionally, all Series 4 warrants were converted to Common Units effective October 2021 at no cost to the warrant holder. The impact of the exchange of Series 4 Preferred Units to Series 5 Preferred Units coupled with the non-cash conversion of Series 4 warrants to Common Units accrued to the benefit of the Series 4 Preferred unitholders, who also own approximately 90% of the Common Units. The actual effect of this conversion was to transfer $22.7 million of value from the Common Unit holders to the Series 4 Preferred Unit holders. As a result of this offering, we issued 2,073.69 units for total proceeds of $132.6 million net of $0.1 million of offering costs. Subsequent to this offering, there were no Series 4 Preferred Units or warrants still outstanding.

The proceeds, in conjunction with cash on hand and borrowings under our credit facility, were used to acquire producing properties and a gas processing plant in the Permian Basin of New Mexico and CO₂ assets in Colorado from Chevron (see Note 2).

Prior to April 1^st of each year, the general partner shall determine the fair value of a Common Unit as of January 1^st of such year. However, the general partner can change the fair value of a Common Unit should circumstances indicate that a material change in value has occurred. The fair value was determined to be $4.00 per Common Unit as of January 1, 2020. The fair value was determined to be $0.40 per Common Unit as of January 1, 2021. The fair value was determined to be $0.87 per Common Unit as of January 1, 2022. The fair value established by the general partner is used for all purposes until the next redetermination.

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The following reflects our partners’ Common Unit and Preferred Unit activity for the years ended December 31, 2021 and 2020:


	2020
(in thousands)	Common Units			Series 3 Preferred Units		Series 4 Preferred Units		Series 5 Preferred Units

Balance, beginning of period		179,198			1,372		—		—

Vesting of restricted units, net of income taxes		1,067			—		—		—

Common units surrendered to pay off share notes		(932	)		—		—		—

Common units received in lieu of distribution		953			—		—		—

Preferred units purchased		—			—		1		—


Balance, December 31		180,286			1,372		1		—


	2021
	Common Units		Series 3 Preferred Units		Series 4 Preferred Units			Series 5 Preferred Units

Balance, beginning of period		180,286		1,372		1			—

Vesting of restricted units, net of income taxes		3,000		—		—			—

Warrants converted to common units		137,438		—		—			—

Common units received in lieu of distribution		32,971		—		—			—

Preferred units purchased		—		—		—			1

Preferred units exchanged for new preferred units		—		—		(1	)		1


Balance, December 31		353,695		1,372		—			2

Distributions

During 2021, we paid in-kind distributions of 32.0 million units with a value of $6.4 million to our Series 4 Preferred holders and 1.0 million units with a value of $1.8 million to our Series 3 Preferred holders. During 2020, we paid in-kind distributions of 1.0 million units with a value of $1.6 million to our Series 3 Preferred holders.

The determination of the amount of future distributions on the Common Units, if any, to be declared and paid is at the sole discretion of the general partner and will depend on our financial condition, earnings and cash flow from operations, the level of debt outstanding, the level of our capital expenditures, our future business prospects and other matters the general partner deems relevant.

See Note 12.

11. Employee Benefit Plans

401(k) Plan

We sponsor a 401(k) benefit plan that allows employees to contribute and defer a portion of their wages. Regardless of an employees’ decision to participate in the 401(k) plan, we make a non-elective contribution equal to 3% of each employees’ wages. Additionally, we have the ability to make a discretionary annual match as determined by the general partner. Employee contributions and non-elective contributions vest immediately while our matching contributions vest 100% upon

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completion of three years of service. All employees over 18 years of age may participate. The plan was put in place January 1, 2013. Company contributions under the plan were $0.7 million in 2021 and $0.7 million in 2020.

Unit Incentive Plans

Unit incentive awards under the 2012 Employee Equity Incentive Plan (2012 Plan) include unit awards which are subject to such restrictions as determined by the general partner. Under the terms of the 2012 Plan, 2.5 million units are available for grants of unit awards. On December 31, 2018, the Plan was amended to increase the amount of units available for grant to 4.5 million units.

A restricted unit is a unit that vests over a period of time and during such time is subject to forfeiture, and may contain such terms as the general partner shall determine. We intend the restricted units under the Plan to serve as a means of incentive compensation for performance. Therefore, participants will not pay any consideration for the restricted units they receive. If a grantee’s employment or service relationship terminates for any reason other than death, the grantee’s unvested restricted units will be automatically forfeited unless the general partner or the terms of the award agreement provide otherwise. Holders of restricted units generally have no voting, dividend or other rights of other unit holders.


	Grant Date Fair Value			Number of Units

Outstanding at December 31, 2019	$	5.50			1,830,874

Vesting		(5.50	)		(1,466,154	)

Grants		—			—

Forfeitures		(5.50	)		(364,720	)


Outstanding at December 31, 2020	$	—			—

We recognized non-cash restricted unit compensation expense of $0.0 million in 2021 and $4.2 million in 2020 related to these shares. In conjunction with the July 2020, capital raise (Note 11), we vested the remaining unvested shares effective July 30, 2020. There was a fully-vested grant of 3,000,000 units in 2021.

12. Revenue from Contracts with Customers

The Company recognizes sales of oil, natural gas, and NGLs when it satisfies a performance obligation by transferring control of the product to a customer, in an amount that reflects the consideration to which the Company expects to be entitled in exchange for the product.

As discussed in Note 10, the Company recognizes the impact of derivative gains and losses as a component of revenue. See table below for the reconciliation of revenue from contracts with customers and derivative gains and losses.


	Year Ended December 31, 2021
	Oil and condensate		Natural gas liquids		Natural gas		Total Revenues
	(in thousands)

Revenue from customers	$	69,625	$	27,394	$	122,348	$	219,367

Unrealized gain (loss) on derivatives		346		481		8,150		8,977

Realized gain (loss) on derivatives		—		—		—		—


Total revenues	$	69,971	$	27,875	$	130,498	$	228,344

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	Year Ended December 31, 2020
	Oil and condensate			Natural gas liquids		Natural gas			Total Revenues
	(in thousands)

Revenue from customers	$	34,885		$	8,660	$	41,914		$	85,459

Unrealized gain (loss) on derivatives		(2,957	)		—		70			(2,887	)

Realized gain (loss) on derivatives		27,142			—		(950	)		26,192


Total Revenues	$	59,070		$	8,660	$	41,034		$	108,764

Natural Gas and NGL Sales

Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or at the inlet of a facility. The midstream provider gathers and processes the product and both the residue gas and the resulting natural gas liquids are sold at the tailgate of the plant. The Company’s natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to the market. We evaluated these arrangements and determined that control of the products transfers at the tailgate of the plant, meaning that the Company is the principal and the third-party purchaser is its customer. As such, we present the gas and NGL sales on a gross basis and the related gathering and processing costs as a component of taxes, transportation, and other on the statement of operations.

Oil and Condensate Sales

Oil production is sold at the wellhead under market-sensitive contracts at an index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received from the customer. This treatment after the adoption of ASC 606 is consistent with the treatment under ASC 605 and has no impact on revenues or expenses on the statement of operations.

Production imbalances

The Company uses the sales method to account for production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy the imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Contract Balances

Under the Company’s product sales contracts, its customers are invoiced once the Company’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or contract liabilities.

Performance Obligations

The majority of the Company’s sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14

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exempting the Company from disclosures of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligation is not required.

13. Accrued Liabilities

Accrued liabilities consist of the following at December 31, 2021 and 2020:


	December 31,
	2021		2020

Accrued production expenses	$	16,815	$	11,083

Accrued severance taxes		3,511		1,182

Accrued ad valorem taxes		2,211		1,057

Accrued capital expenditures		541		663

Other accrued liabilities		680		172


Total accrued liabilities	$	23,758	$	14,157

14. Supplemental Cash Flow Information

The statement of cash flows excludes the following non-cash transactions:

•

The following restricted share activity (Note 12):

•

No forfeitures in 2021 and forfeitures of 364,720 restricted units in 2020

•

The payment of in-kind dividends of 32,970,580 units in 2021 and 952,639 units in 2020 (Note 12).

•

The exchange of 533.63 Series 4 Preferred Units for 747.09 Series 5 Preferred Units (Note 11).

•

Accrued capital expenditures were $0.5 million at December 31, 2021 and $0.7 million at December 31, 2020.

Interest payments totaled $4.1 million for in 2021 and $7.3 million in 2020. State income tax payments totaled $0.1 million in 2021 and $0.1 million in 2020.

15. Subsequent Events

We have evaluated subsequent events through the date the financial statements were available to be issued. See Note 2 for discussion of 2022 acquisition.

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16. Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited)

All of our operations are directly related to oil and gas producing activities located in the United States primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.

Costs Incurred Related to Oil and Gas Producing Activities

The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes for each year:


(in thousands)
	2021		2020

Acquisition of proved properties, net	$	181,651	$	15,138

Acquisition of unproved properties		67		307

Development		8,142		5,520

Asset retirement obligation incurred upon acquisition		10,741		54,902


Total costs incurred	$	200,601	$	75,867

Proved Reserves

Our proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Proved reserves exclude volumes deliverable to others under production payments or retained interests.

Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. No provision is included for federal income taxes since our future net cash flows are not subject to taxation. Limited liability companies are subject to the Texas margin tax.

Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. Such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values as of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired (Note 8).

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The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as effected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.


*Proved Reserves*	Oil (Bbls)			Natural Gas Liquids (Bbls)			Gas (Mcf)			Oil Equivalents (Boe)
(in thousands)

December 31, 2019		24,002.0			4,586.2			107,103.4			46,438.8

Extensions, additions and discoveries		19.8			1.5			32.3			26.7

Revisions		(4,067.5	)		(2,080.4	)		(50,269.3	)		(14,526.2	)

Production		(940.1	)		(860.2	)		(22,131.6	)		(5,488.9	)

Purchase in place		590.6			6,664.1			208,438.1			41,994.4


December 31, 2020		19,604.8			8,311.2			243,172.9			68,444.8

Extensions, additions and discoveries		38.3			14.5			6,048.3			1,060.9

Revisions		2,758.8			7,277.1			152,978.3			35,532.3

Production		(1,033.0	)		(1,088.8	)		(30,589.7	)		(7,220.1	)

Purchase in place		27,236.7			3,513.6			7,666.1			32,028.0


December 31, 2021		48,605.6			18,027.6			379,275.9			129,845.9


*Proved Developed Reserves*	Oil (Bbls)		Natural Gas Liquids (Bbls)		Gas (Mcf)		Oil Equivalents (Boe)
(in thousands)

December 31, 2019		13,106.5		4,586.2		80,755.3		31,151.9


December 31, 2020		9,787.7		8,311.2		218,396.9		54,498.4


December 31, 2021		30,207.9		17,434.2		353,214.9		106,511.3


*Proved Undeveloped Reserves*	Oil (Bbls)		Natural Gas Liquids (Bbls)		Gas (Mcf)		Oil Equivalents (Boe)
(in thousands)

December 31, 2019		10,895.5		—		26,348.1		15,286.9


December 31, 2020		9,817.1		—		24,776.0		13,946.4


December 31, 2021		18,397.7		593.4		26,061.0		23,334.6

In 2020, the 42.0 Mboe of purchases in place represent the reserves acquired from Southland Royalty in June 2020. The 14.5 Mboe of downward revisions in proved of reserves for 2020 were the result of a combination of lower commodity prices (17.4 Mboe) partially offset by changes in the development plan and forecast revisions (2.9 Mboe).

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In 2021, the 32.0 Mboe of purchases in place represent the reserves acquired from Chevron in November 2021 (24.9 Mboe) and in December 2021 (7.1 Mboe). The 1.1 MBoe of extensions, additions and discoveries in proved reserves in 2021 were primarily related to drilling the San Juan Basin. The 35.5 MBoe of upward revisions in proved of reserves for 2021 were the result of a combination of higher commodity prices (34.9 MBoe) and changes in the development plan (0.6 MBoe).


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	December 31,			December 31,
	2021			2020
(in thousands)

Future cash inflows	$	4,468,597		$	1,049,560

Future costs:

Production		(1,988,988	)		(531,684	)

Development		(365,289	)		(297,570	)

Future income tax		(4,110	)		48


Future net cash flows		2,110,210			220,354

10% annual discount		(1,123,593	)		(65,916	)


Standardized measure	$	986,617		$	154,438


*Changes in Standardized Measure of*	For the Year Ended December 31,
*Discounted Future Net Cash Flows*	2021			2020
(in thousands)

Standardized measure, beginning of period	$	154,438		$	315,023

Revisions:

Prices and costs		205,842			(261,185	)

Quantity estimates		76,737			(29,789	)

Income tax		(1,933	)		789

Future development costs		2,715			18,370

Accretion of discount		15,444			31,502

Production rates and other		42,064			42,303


Net revisions		340,869			(198,010	)

Additions and discoveries		20,272			150

Production		(93,042	)		(7,085	)

Development costs		13,973			11,639

Purchases in place		550,107			32,721


Net change		832,179			(160,585	)


Standardized measure, December 31	$	986,617	(a)	$	154,438	(b)

(a)

The December 31, 2021 standardized measure includes a reduction of $213.1 million ($213.6 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2021 includes a liability of $104.5 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.

(b)

The December 31, 2020 standardized measure includes a reduction of $201.9 million ($202.3 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2020 includes a liability of $100.7 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.

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Price and cost revisions are primarily the net result of changes in prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.

Average realized oil prices used in the estimation of proved reserves and calculation of the standardized measure were $64.76 for 2021 and $37.77 for 2020. Average realized natural gas liquids prices were $19.62 for 2021 and $7.38 for 2020. Average realized gas prices were $2.31 for 2021 and $1.03 for 2020. We used 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period.

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MORNINGSTAR PARNTERS, L.P.

Unaudited Condensed Financial Statements

For the nine months ended September 30, 2022 and 2021

MORNINGSTAR PARTNERS, L.P.

Condensed Balance Sheets

(in thousands)


	September 30, 2022			December 31, 2021
	(Unaudited)

ASSETS

Current Assets:

Cash and cash equivalents	$	11,148		$	7,547

Accounts receivable, net		49,424			34,124

Derivative fair value		2,900			10,632

Other		10,888			4,793


Total Current Assets		74,360			57,096


Property and Equipment, at cost – successful efforts method:

Proved properties		1,448,108			1,376,476

Unproved properties		18,726			18,677

Other		82,017			69,254


Total Property and Equipment		1,548,851			1,464,407

Accumulated depreciation, depletion and amortization		(734,409	)		(704,080	)


Net Property and Equipment		814,442			760,327


Other Assets:

Note receivable from related party		7,130			7,132

Derivative fair value		187			4,912

Other		5,736			3,353


Total Other Assets		13,053			15,397


TOTAL ASSETS	$	901,855		$	832,820


LIABILITIES AND PARTNERS’ CAPITAL

Current Liabilities:

Accounts payable	$	13,031		$	3,965

Accrued liabilities		36,248			23,758

Derivative fair value		39,967			6,450

Other current liabilities		2,404			1,100


Total Current Liabilities		91,650			35,273


Long-term Debt		132,100			152,100


Other Liabilities:

Asset retirement obligation		110,296			103,389

Derivative fair value		17,559			117

Other liabilities		758			582


Total Other Liabilities		128,613			104,088


Commitments and Contingencies

Partners’ Capital:

Partners’ capital		549,492			541,359


TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	901,855		$	832,820

See accompanying notes to the Condensed Financial Statements

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MORNINGSTAR PARTNERS, L.P.

Condensed Statements of Operations (Unaudited)

(in thousands)


	Nine months ended September 30,
	2022			2021

REVENUES

Oil and condensate	$	120,703		$	40,061

Natural gas liquids		29,268			18,086

Gas		54,067			80,783


Total Revenues		204,038			138,930


EXPENSES

Production		93,961			45,833

Exploration		281			81

Taxes, transportation and other		72,993			37,941

Depreciation, depletion and amortization		30,329			28,054

Accretion of discount in asset retirement obligation		4,508			3,513

General and administrative		572			3,646


Total Expenses		202,644			119,068


OPERATING INCOME		1,394			19,862


OTHER INCOME (EXPENSE)

Other income		18,677			9,128

Interest income		68			11

Interest expense		(5,526	)		(3,722	)


Total Other Income		13,219			5,417


NET INCOME	$	14,613		$	25,279

See accompanying notes to the Condensed Financial Statements

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MORNINGSTAR PARTNERS, L.P.

Condensed Statements of Cash Flows (Unaudited)

(in thousands)


	Nine months ended September 30,
	2022			2021

OPERATING ACTIVITIES

Net income	$	14,613		$	25,279

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization		30,329			28,054

Accretion of discount in asset retirement obligation		4,508			3,513

Gain on forgiveness of long-term debt		—			(9,152	)

Derivative fair value loss		133,658			—

Net cash paid to counterparties		(70,242	)		—

Other non-cash items		537			562

Changes in operating assets and liabilities (a)		(9,735	)		(1,256	)


Cash Provided by Operating Activities		103,668			47,000


INVESTING ACTIVITIES

Proved property acquisitions		(49,765	)		(13,533	)

Development costs		(7,865	)		(7,646	)

Unproved property acquisitions		(49	)		(67	)

Other property and asset additions		(12,764	)		(169	)


Cash Used by Investing Activities		(70,443	)		(21,415	)


FINANCING ACTIVITIES

Proceeds from long-term debt		1,099,000			1,052,000

Payments on long-term debt		(1,119,000	)		(1,087,000	)

Debt issuance costs		(132	)		(89	)

Capitalized offering costs		(3,012	)		—

Distributions		(6,480	)		—


Cash Used by Financing Activities		(29,624	)		(35,089	)


INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		3,601			(9,504	)

Cash and Cash Equivalents, beginning of period		7,547			21,933


Cash and Cash Equivalents, end of period	$	11,148		$	12,429


(a) Changes in Operating Assets and Liabilities

Accounts receivable	$	(19,711	)	$	(1,943	)

Other current assets		(6,093	)		(1,741	)

Aid-in-construction		238			—

Current liabilities		16,603			2,888

Other operating liabilities		(772	)		(460	)


	$	(9,735	)	$	(1,256	)

See accompanying notes to the Condensed Financial Statements

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MORNINGSTAR PARTNERS, L.P.

Condensed Statements of Members’ Equity (Unaudited)

(in thousands)


	Series 3 Preferred		Series 5 Preferred		Common			Total

Balances, December 31, 2021	$	34,295	$	206,074	$	300,990		$	541,359

Net income		—		—		14,613			14,613

Increase in members’ equity from in-kind distributions		—		—		857			857

Distributions		—		—		(6,480	)		(6,480	)

In-kind distributions		—		—		(857	)		(857	)


Balances, September 30, 2022	$	34,295	$	206,074	$	309,123		$	549,492

See accompanying notes to the Condensed Financial Statements

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MORNINGSTAR PARTNERS, L.P.

Notes to Financial Statements

1. Organization and Description of the Business

MorningStar’s assets include its investment in Cross Timbers Energy, LLC (Cross Timbers Energy), an unincorporated joint venture between XTO Energy Inc., HHE Energy Company and XH LLC (the XTO entities) and MorningStar. The XTO entities and MorningStar each own 50% of Cross Timbers Energy, and MorningStar is the manager of the joint venture. The joint venture is governed by a Member Management Committee (MMC) and is comprised of six representatives, three each from the XTO entities and MorningStar, with each group having one voting member. All matters that come before the MMC require the unanimous consent of the voting members. On the last day of each calendar quarter, Cross Timbers Energy distributes all excess cash to the members based on their ownership percentage of 50% each, except for earnings from the note receivable which is owned 95% by the XTO entities and 5% by MorningStar (Note 5). Cross Timbers Energy’s properties are located primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.

MorningStar also has a wholly-owned subsidiary, MorningStar Operating, LLC which owns oil and gas assets located primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.

2. Basis of Presentation and Significant Accounting Policies

The condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and on the same basis as our audited financial statements as of December 31, 2021. The condensed balance sheet as of September 30, 2022 and the condensed statements of operations and cash flows for the periods presented herein are not audited but reflect all adjustments that are of a normal recurring nature and are necessary for a fair statement of results for the periods shown. Certain information and note disclosures normally included in annual financial statements have been omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission. Because the condensed interim financial statements do not include all of the information and notes required by US GAAP for a complete set of financial statements, they should be read in conjunction with the audited financial statements referred to above. The results and trends in these interim financial statements may not be indicative of results for the full year.

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Significant Accounting Policies

For a complete description of MorningStar ’s significant accounting policies, see our annual audited financial statements.

3. Acquisitions

In December 2021, MorningStar completed the acquisition of producing properties in the Permian Basin of Texas from Chevron for approximately $43.8 million. Our purchase price allocation included $47.2 million to proved properties and $3.4 million to asset retirement obligation. The acquisition is subject to typical post-closing adjustments. The acquisition was funded by cash on hand and borrowings from our credit facility.

In November 2021, MorningStar completed the acquisition of producing properties and a gas processing plant in the Permian Basin of New Mexico and CO₂ assets in Colorado from Chevron for approximately $179.3 million. Our purchase price allocation included $150.9 million to proved properties, $34.4 million to other properties, $3.6 million to other current assets, $2.2 million to other current liabilities and $7.4 million to asset retirement obligation. The acquisition was funded by cash on hand from the October 2021 capital raise and borrowings from our credit facility.

4. Related Party Transactions

We earned management fees from Cross Timbers Energy of $4.4 million for the nine months ended September 30, 2022 and $4.7 million for the nine months ended September 30, 2021.

5. Debt


(in thousands)	September 30, 2022		December 31, 2021

Credit Facility, 6.4% at September 30, 2022 and 4.0% at December 31, 2021	$	125,000	$	145,000

MorningStar Partners Loan, 5.9% at September 30, 2022 and 3.4% at December 31, 2021	$	7,100	$	7,100


Total Long-term Debt	$	132,100	$	152,100

November 2021 MorningStar Partners Credit Facility

On November 1, 2021, we entered into a new four-year, $165 million senior secured credit facility with certain commercial banks. The facility has a maturity date of November 1, 2025. We

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use the facility for general corporate purposes. In connection with entering into the credit facility, as of September 30, 2022, we incurred financing fees and expenses of approximately $2.8 million before accumulated amortization of $0.6 million. These costs are being amortized over the life of the credit facility. Such amortized expenses are recorded as interest expense on the statements of operations.

Redetermination of the borrowing base under the credit facility, is based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in March and September, as well as upon requested interim redeterminations, by the lenders at their sole discretion. We also have the right to request additional borrowing base redeterminations each year at our discretion. Significant declines in commodity prices may result in a decrease in the borrowing base. These borrowing base declines can be offset by any commodity price hedges we enter. Our obligations under the credit facility are secured by all assets of the Company, including without limitation (i) our interest in the Cross Timbers Energy, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by Cross Timbers Energy and (iv) any oil and gas properties owned directly by MorningStar or its wholly-owned subsidiaries. We are required to maintain (i) a current ratio greater than 1.0 and current assets shall include availability under the credit facility but shall exclude the fair value of derivative instruments and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. The total indebtedness-to-EBITDAX calculation is limited to Cross Timbers Energy’s EBITDAX that has been paid in cash to MorningStar through distributions, MorningStar Operating’s EBITDAX results and realized hedge gains less realized hedge losses and the consolidated expenses of MorningStar and its subsidiaries. EBITDAX means net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. We were in compliance with all financial and other covenants of the credit facility, except the covenant regarding hedge volumes required as of September 30, 2022. We received a waiver for this exception in September 2022. This waiver, which will continue through the next scheduled redetermination in March 2023, allows us to reduce the hedging requirement from 30 months to 18 months beginning January 1, 2023 and from 50% to 45% of the reasonably anticipated projected production. We believe that we have a sufficient combination of resources and operating flexibility to ensure that we remain in compliance with our debt covenants for at least the next 12 months.

At our election, interest on borrowings under the credit facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base.

MorningStar Partners Loan

On September 30, 2016, MorningStar entered into a $27.1 million loan agreement with Cross Timbers. The proceeds for the loan were taken from the cash held by the offshore subsidiary of Exxon Mobil Corporation and the loan was assigned to the offshore subsidiary (Note 6). The loan matures on January 31, 2026, but is automatically extended should our credit facility be extended. In all instances, this loan will mature ninety-one days after the maturity of the current Morningstar

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credit facility. Interest on the loan is the lesser of (a) London Interbank Offered Rate (“LIBOR”) plus three and one-quarter of one percent (3.25%) per annum, adjusted monthly or (b) the highest rate permitted by applicable law. The note is unsecured, but we are required to stay in compliance with terms of our current credit facility.

6. Note Receivable from Related Party

As of September 30, 2022 and December 31, 2021, we, through our 5% ownership interest in investment assets at Cross Timbers Energy, had a note receivable totaling $7.1 million outstanding with a highly-rated, offshore subsidiary of Exxon Mobil Corporation. Under the terms of the agreement, there is no stated maturity date and Cross Timbers Energy may demand repayment of all or any portion of the outstanding balance on two business days’ notice. Interest is earned based on the one-month SOFR rate and is paid monthly. Interest income totaled less than $0.1 million in the first nine months of 2022 and 2021.

The note receivable is treated as a non-current asset, since Cross Timbers does not have any intention of demanding repayment of all or any portion of the outstanding balance at this time. Repayment would require the approval of the Cross Timbers Energy MMC.

7. Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of changes in MorningStar’s asset retirement obligation activity for the nine months ended September 30, 2022:


	(in thousands)

Asset retirement obligation, January 1	$	104,489

Liability incurred upon acquiring and drilling wells		3,356

Liability settled upon plugging and abandoning wells		(957	)

Accretion of discount expense		4,508


Asset retirement obligation, September 30		111,396

Less current portion		(1,100	)


Asset retirement obligation, long term	$	110,296

8. Commitments and Contingencies

9. Fair Value

We use commodity-based and financial derivative contracts to manage exposures to commodity price. We do not hold or issue derivative financial instruments for speculative or

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trading purposes. We periodically enter into futures contracts, costless collars, energy swaps, swaptions and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales (Note 10).

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at September 30, 2022 and December 31, 2021. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	Asset (Liability)
	September 30, 2022						December 31, 2021
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value

Note receivable from related party	$	7,130		$	7,130		$	7,132		$	7,132


Long-term debt	$	(132,100	)	$	(132,100	)	$	(152,100	)	$	(152,100	)


Derivative asset	$	3,087		$	3,087		$	15,544		$	15,544


Derivative liability	$	(57,526	)	$	(57,526	)	$	(6,567	)	$	(6,567	)

The fair value of our note receivable from related party approximates the carrying amount because the interest rate is based on current market interest rates and can be called upon two business days’ notice (Note 6). The fair value of our long-term debt approximates the carrying amount because the interest rate is reset periodically at then current market rates (Note 5).

The fair value of our note receivable from related party (Note 6), derivative asset/(liability) (Note 10) and our long-term debt (Note 5) is measured using Level II inputs, and are determined by either market prices on an active market for similar assets or other market-corroborated prices. Counterparty credit risk is considered when determining the fair value of our note receivable and net derivative asset. Since our counterparty is highly rated, the fair value of our note receivable from related party does not require an adjustment to account for the risk of nonperformance by the counterparty, however, an adjustment for counterparty credit risk has been applied to the net derivative asset (liability).

The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.


	Fair Value Measurements
	September 30, 2022					December 31, 2021
(in thousands)	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)

Note receivable from related party	$	7,130		$	—	$	7,132		$	—


Long-term debt	$	(132,100	)	$	—	$	(152,100	)	$	—


Derivative asset	$	3,087		$	—	$	15,544		$	—


Derivative liability	$	(57,526	)	$	—	$	(6,567	)	$	—

F-52

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Commodity Price Hedging Instruments

The fair value of our derivatives contracts consists of the following:


	Asset Derivatives				Liability Derivatives
(in thousands)	September 30, 2022		December 31, 2021		September 30, 2022			December 31, 2021

Derivatives not designated as hedging instruments:

Crude oil futures and differential swaps	$	74	$	2,342	$	(7,993	)	$	(1,996	)

Natural gas liquids futures	$	412	$	685	$	(3,372	)	$	(204	)

Natural gas futures, collars and basis swaps	$	2,601	$	12,517	$	(46,161	)	$	(4,367	)


Total	$	3,087	$	15,544	$	(57,526	)	$	(6,567	)

F-53

Derivative fair value (gain) loss, included as part of the related revenue line on the consolidated income statements, comprises the following realized and unrealized components:


	Nine Months Ended September 30,
(in thousands)	2022		2021

Net cash paid to counterparties	$	70,242	$	—

Non-cash change in derivative fair value	$	63,416	$	—


Derivative fair value loss	$	133,658	$	—

Concentrations of Credit Risk

10. Commodity Sales Commitments

Crude Oil


			Weighted Average
			NYMEX
Production Period	Bbls per Day		Price per Bbl

October 2022—December 2022		3,500	$	71.28

January 2023—December 2023		2,500	$	68.87

January 2024—June 2024		2,000	$	63.27

F-54


			Weighted Average
			Sell Basis
Production Period	Bbls per Day		Price per Bbl (a)

October 2022—December 2022		3,000	$	0.55

January 2023—December 2023		3,000	$	1.05

(a)	Increases to NYMEX oil price for delivery location


			Weighted Average
			Roll
Production Period	Bbls per Day		Price per Bbl (a)

October 2022—December 2022		5,000	$	0.50

January 2023—December 2023		1,000	$	0.68

(a)	Increases to NYMEX oil price for roll component

Net settlement losses on oil futures and sell basis swap contracts decreased oil revenues by $28.7 million in the first nine months of 2022 and $0.0 in the first nine months of 2021. An unrealized loss decreased oil revenues by $8.3 million in the first nine months of 2022 and $0.0 in the first nine months of 2021.

Natural Gas Liquids


			Weighted Average

			NGL OPIS

Production Period	Gallons per Day		Price per Gallon
Ethane

October 2022—December 2022		63,000	$	0.33

January 2023—December 2023		63,000	$	0.27

January 2024—June 2024		63,000	$	0.23

Propane

October 2022—December 2022		31,500	$	1.01

Net settlement losses on NGL futures contracts decreased NGL revenues by $5.0 million in the first nine months of 2022 and $0.0 in the first nine months of 2021. An unrealized loss decreased NGL revenues by $3.4 million in the first nine months of 2022 and $0.0 in the first nine months of 2021.

F-55

Natural Gas


			Weighted Average

			NYMEX

Production Period	MMBtu per Day		Price per MMBtu

October 2022—December 2022		45,000	$	4.23

January 2023—December 2023		35,000	$	3.51

January 2024—June 2024		30,000	$	3.26

We have also entered into gas collars that set a ceiling and floor price for the production and periods shown below.


			Weighted Average

			NYMEX Price per MMBtu

Production Period	MMBtu per Day		Floor		Ceiling

October 2022—December 2022		15,000	$	3.50	$	5.85

January 2023—March 2023		5,000	$	5.00	$	9.85

January 2024—June 2024		5,000	$	3.75	$	7.25


			Weighted Average

			Sell Basis

Production Period	MMBtu per Day		Price per MMBtu(a)

October 2022—December 2022		70,000	$	0.22

January 2023—December 2023		20,000	$	0.15

(a)	Reductions to NYMEX gas price for delivery location

Net settlement losses on gas futures and sell basis swap contracts decreased gas revenues by $36.5 million in the first nine months of 2022 and $0.0 in the first nine months of 2021. An unrealized loss to record the fair value of derivative contracts decreased gas revenues by $51.7 million in the first nine months of 2022 and $0.0 in the first nine months of 2021.

11. Revenue from Contracts with Customers

F-56


	For the Nine Months Ended September 30, 2022
	Oil and condensate			Natural gas liquids			Natural gas			Total Revenues
	(in thousands)

Revenue from customers	$	157,698		$	37,673		$	142,325		$	337,696

Unrealized gain (loss) on derivatives		(8,264	)		(3,442	)		(51,710	)		(63,416	)

Realized gain (loss) on derivatives		(28,731	)		(4,963	)		(36,548	)		(70,242	)


Total revenues	$	120,703		$	29,268		$	54,067		$	204,038


	For the Nine Months Ended September 30, 2021
	Oil and condensate		Natural gas liquids		Natural gas		Total Revenues
	(in thousands)

Revenue from customers	$	40,061	$	18,086	$	80,783	$	138,930

Unrealized gain (loss) on derivatives		—		—		—		—

Unrealized gain (loss) on derivatives		—		—		—		—


Total Revenues	$	40,061	$	18,086	$	80,783	$	138,930

Natural Gas and NGL Sales

Oil and Condensate Sales

Production imbalances

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reserves from the well is insufficient to satisfy the imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Contract Balances

Performance Obligations

The majority of the Company’s sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosures of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original duration of one year or less.

12. Accrued Liabilities

Accrued liabilities consist of the following at September 30, 2022 and December 31, 2021:


	September 30, 2022		December 31, 2021

Accrued production expenses	$	21,578	$	16,815

Accrued severance taxes		4,824		3,511

Accrued capital expenditures		4,564		541

Accrued ad valorem taxes		3,052		2,211

Other accrued liabilities		2,230		680


Total accrued liabilities	$	36,248	$	23,758

13. Supplemental Cash Flow Information

Interest payments totaled $5.4 million for the nine months ended September 30, 2022 and $3.2 million for the nine months ended September 30, 2021. Income tax payments were $0.5 million during the nine months ended September 30, 2022 and $0.1 million during the nine months ended September 30, 2021.

14. Subsequent Events

We have evaluated subsequent events through the date the financial statements were available to be issued.

F-58

VACUUM PROPERTIES

Statement of Revenues and Direct Operating Expenses

Period from January 1, 2021 through October 31, 2021

F-59

Auditor Report

Independent Auditors’ Report

To the Partners

MorningStar Partners, L.P.:

We have audited the accompanying statement of revenues and direct operating expenses (the Statement) of certain oil and gas properties acquired from Chevron U.S.A. Inc. (the Vacuum Properties) by MorningStar Partners, L.P. (the Company) for the period from January 1, 2021 to October 31, 2021, and the related notes to the Statement.

Management’s Responsibility for the Statement

Management is responsible for the preparation and fair presentation of the Statement in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the Statement that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the Statement based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statement is free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statement. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the Statement, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the Statement in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statement.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Basis of Accounting

The accompanying Statement referred to above was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The Statement is not intended to be a complete presentation of the operations of the Vacuum Properties.

Opinion

In our opinion, the Statement referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Vacuum Properties for the period from January 1, 2021 to October 31, 2021, in accordance with U.S. generally accepted accounting principles.

F-60

Other Matter

U.S. generally accepted accounting principles require that the Supplementary Oil and Gas Disclosures contained herein be presented to supplement the basic Statement. Such information, although not a part of the basic Statement, is required by the Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic Statement in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic Statement, and other knowledge we obtained during our audit of the basic Statement. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

LOGO

Dallas, Texas

August 31, 2022

F-61

MorningStar Operating LLC

Statement of Revenues and Direct Operating

Expenses of the Vacuum Properties (as described in Note 1)

(in thousands)


	Period From January 1, 2021 to October 31, 2021

REVENUES

Oil and condensate	$	48,215

Natural gas liquids		1,935

Gas		178

Other		3,173


Total Revenues		53,501


DIRECT OPERATING EXPENSES

Production		30,150

Taxes, transportation and other		5,062


Total Direct Operating Expenses		35,212


Revenues in Excess of Direct Operating Expenses	$	18,289

See accompanying notes to Statements of Revenues and Direct Operating Statements.

F-62

Notes to the Statements of Revenues and Direct Operating Expenses

of the Vacuum Properties

(1) Basis of Presentation

On November 1, 2021, MorningStar Partners, LP and MorningStar Operating LLC (collectively, the “MorningStar Entities”) completed the acquisition from Chevron U.S.A. Inc., Chevron Midcontinent, L.P. and XBM Production, L.P. (collectively, the “Chevron Entities”) of producing properties and a gas processing plant in the Vacuum field of New Mexico and carbon dioxide (CO₂) assets in Colorado (“Vacuum Properties”) for approximately $175.4 million. The purchase price was allocated primarily to proved properties and the gas processing and gathering plant. The acquisition was funded by cash contributions from MorningStar Partners’ limited partners and borrowings under the MorningStar Partners credit facility.

The accompanying audited statement includes revenues from oil, natural gas liquids and natural gas production and direct operating expenses associated with the Vacuum Properties and were derived from the Chevron Entities’ consolidated historical accounting records. The accompanying statement varies from a complete income statement in accordance with US GAAP in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Vacuum Properties including, but not limited to, general and administrative expenses, interest expense and income tax expense. These costs were not separately allocated to the Vacuum Properties in the accounting records of the Chevron Entities. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Vacuum Properties had it been a MorningStar Entities property due to the differing size, structure, operations and accounting policies of the Chevron Entities and the MorningStar Entities. The accompanying statement also does not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs that the MorningStar Entities will incur upon the allocation of the purchase price paid for the Vacuum Properties. Furthermore, no balance sheet has been presented for the Vacuum Properties because the acquired properties were not accounted for as a separate subsidiary or division of the Chevron Entities and complete financial statements are not available, nor has information about the Vacuum Properties’ operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statement of Revenues and Direct Operating Expenses of the Vacuum Properties is presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

This Statement of Revenues and Direct Operating Expenses is not indicative of the results of operations for the Vacuum Properties on a go forward basis.

(2) Summary of Significant Accounting Policies

Use of Estimates—The Statement of Revenues and Direct Operating Expenses is derived from the historical operating statements of the Chevron Entities. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results could be different from those estimates.

Revenue Recognition—Total revenues in the accompanying statements include the sale of crude oil, natural gas liquids and natural gas, net of royalties as well as related income from the

F-63

gas processing plant and sales of CO₂. The Chevron Entities recognize revenues upon the satisfaction of the applicable performance obligation, which occurs at the point in time when control of the product transfers to a customer, in an amount that reflects the consideration to which the Chevron Entities expects to be entitled in exchange for such product.

During the period from January 1, 2021 to October 31, 2021, no customers accounted for more than 10% of the total revenues of the Vacuum Properties.

Direct Operating Expenses—Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Vacuum Properties. The direct operating expenses include lease operating, production taxes, processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities.

(3) Contingencies

The activities of the Vacuum Properties may become subject to potential claims and litigation in the normal course of operations. The MorningStar Entities do not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Vacuum Properties.

(4) Subsequent Events

The MorningStar Entities have evaluated events through August 31, 2022, the date the Statements of Revenues and Direct Operating Expenses were available to be issued, and are not aware of any events that have occurred that require adjustments to or disclosure in the financial statements.

Supplementary Oil and Gas Disclosures (Unaudited)

Supplemental reserve information

The following unaudited supplemental reserve information summarizes the net proved reserves of oil, natural gas liquids and natural gas and the standardized measure thereof attributable to the Vacuum Properties as of November 1, 2021 and December 31, 2020 and for the period from January 1, 2021 to November 1, 2021 attributable to the Vacuum Properties. All of the reserves are located in the United States. The reserve disclosures are based on reserve studies prepared in accordance with the guidelines established by the SEC.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil, natural gas liquids and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil, natural gas liquids and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil, natural gas liquids and natural gas sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents

F-64

estimates only and should not be construed as the current market value of the estimated oil, natural gas liquids and natural gas reserves attributable to the Vacuum Properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Vacuum Properties and any adjustments in the projected economic life of such property resulting from changes in product prices.

Estimated quantities of oil, NGL and gas reserves

The following table sets forth certain data pertaining to the Vacuum Properties proved developed reserves as of November 1, 2021 and December 31, 2020 and for the period from December 31, 2020 to November 1, 2021.


	Oil (MBbl)			NGL (MBbl)			Gas (MMCF)			Total (MBoe)

November 1, 2021

Proved Reserves

Beginning balance, December 31, 2020		19,042			3,302			2,317			22,730

Revision of previous estimates		2,549			193			294			2,791

Production		(747	)		(48	)		(84	)		(809	)


Ending balance, November 1, 2021		20,844			3,447			2,527			24,712


Proved Developed Reserves December 31		12,426			2,738			1,950			15,489


Proved Undeveloped Reserves December 31		6,616			564			367			7,241


Proved Developed Reserves November 1		14,097			2,861			2,146			17,316


Proved Undeveloped Reserves November 1		6,747			586			381			7,396

Revisions of previous estimates for all periods are primarily attributed to increases in commodity prices. As commodity prices increase, the estimated useful life of the wells extend, thereby increasing the ultimate recoverable reserves.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of Discounted Future Net Cash Flows (excluding income tax expense) relating to proved crude oil, natural gas liquids and natural gas reserves is presented below:


	November 1, 2021

Future cash inflows	$	1,421,961

Future development and abandonment costs(a)		(48,151	)

Future production expense		(712,056	)


Future net cash flows		661,754

Discounted at 10% per year		(384,315	)


Standardized measure of discounted future net cash flows	$	277,439

(a)	Future development and abandonment costs include $22.1 million as of November 1, 2021 and as of December 31, 2020, of undiscounted future asset retirement expenditures estimated as of those dates using current estimates of future abandonment costs.

F-65

The Standardized Measure of Discounted Future Net Cash Flows (discounted at 10%) from production of proved reserves was developed as follows:

•

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on current economic conditions.

•

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from proved properties and the present value thereof are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices are held constant throughout the life of the properties, except where such guidelines permit alternate treatment. Average realized oil prices used in the estimation of proved reserves and calculation of the standardized measure were $58.41 for 2021 and $37.28 for 2020. Average realized natural gas liquids prices were $27.86 for 2021 and $18.61 for 2020. Average realized gas prices were $2.13 for 2021 and $0.91 for 2020.

•

The future gross revenue streams were reduced by estimated future operating costs and future development and abandonment costs, all of which were based on current costs in effect at the date presented and held constant throughout the life of the properties.

As described in Note 1, these Statements of Revenue and Direct Operating Expenses do not include income tax expense or balance sheet information; therefore, income tax and capital expenditure estimates were omitted from the Standardized Measure of Discounted Future Net Cash Flows calculation. The principal sources of changes in the Standardized Measure of Discounted Future Net Cash Flows for each of the periods presented below are as follows:


	Period From December 31, 2020 to October 31, 2021

Balance, beginning of year	$	109,720

Oil and gas sales, net of production costs		(18,289	)

Net change in sales prices and production costs		136,525

Changes in production rates (timing) and other		2,754

Revision of quantity estimates		35,757

Accretion of discount		10,972


Standardized measure of discounted future net cash flows	$	277,439

F-66

APPENDIX A

FORM OF

SEVENTH AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

TXO ENERGY PARTNERS, L.P.

A Delaware Limited Partnership

Dated as of

, 2023

TABLE OF CONTENTS


		Page
Article I DEFINITIONS			A-1

Section 1.1	Definitions		A-1
Section 1.2	Construction		A-13

Article II ORGANIZATION			A-13

Section 2.1	Formation		A-13
Section 2.2	Name		A-13
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices		A-13
Section 2.4	Purpose and Business		A-14
Section 2.5	Powers		A-14
Section 2.6	Term		A-14
Section 2.7	Title to Partnership Assets		A-14

Article III RIGHTS OF LIMITED PARTNERS			A-15

Section 3.1	Limitation of Liability		A-15
Section 3.2	Management of Business		A-15
Section 3.3	Outside Activities of the Limited Partners		A-15
Section 3.4	Rights of Limited Partners		A-15

Article IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS			A-16

Section 4.1	Certificates		A-16
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates		A-17
Section 4.3	Record Holders		A-17
Section 4.4	Transfer Generally		A-18
Section 4.5	Registration and Transfer of Limited Partner Interests		A-18
Section 4.6	Transfer of the General Partner’s General Partner Interest		A-19
Section 4.7	Restrictions on Transfers		A-19
Section 4.8	Eligibility Certifications; Ineligible Holders		A-19
Section 4.9	Redemption of Partnership Interests of Ineligible Holders		A-20

Article V CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS			A-21

Section 5.1	Contributions by the General Partner and its Affiliates		A-21
Section 5.2	Contributions by Limited Partners		A-22
Section 5.3	Interest and Withdrawal		A-22
Section 5.4	Capital Accounts		A-22
Section 5.5	Issuances of Additional Partnership Interests		A-25
Section 5.6	Limited Preemptive Right		A-25
Section 5.7	Splits and Combinations		A-26
Section 5.8	Fully Paid and Non-Assessable Nature of Limited Partner Interests		A-26
Section 5.9	Deemed Capital Contributions by Partners		A-26

Article VI ALLOCATIONS AND DISTRIBUTIONS			A-26

Section 6.1	Allocations for Capital Account Purposes		A-26
Section 6.2	Allocations for Tax Purposes		A-30
Section 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders		A-32

Article VII MANAGEMENT AND OPERATION OF BUSINESS			A-32

Section 7.1	Management		A-32
Section 7.2	Replacement of Fiduciary Duties		A-34

A-i


Section 7.3	Certificate of Limited Partnership	A-34
Section 7.4	Restrictions on the General Partner’s Authority to Sell Assets of the Partnership Group	A-35
Section 7.5	Reimbursement of the General Partner	A-35
Section 7.6	Outside Activities	A-36
Section 7.7	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members	A-37
Section 7.8	Indemnification	A-37
Section 7.9	Liability of Indemnitees	A-38
Section 7.10	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	A-39
Section 7.11	Other Matters Concerning the General Partner	A-41
Section 7.12	Purchase or Sale of Partnership Interests	A-42
Section 7.13	Registration Rights of the General Partner and its Affiliates	A-42
Section 7.14	Reliance by Third Parties	A-45

Article VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS		A-46

Section 8.1	Records and Accounting	A-46
Section 8.2	Fiscal Year	A-46
Section 8.3	Reports	A-46

Article IX TAX MATTERS		A-47

Section 9.1	Tax Returns and Information	A-47
Section 9.2	Tax Elections	A-47
Section 9.3	Tax Controversies	A-47
Section 9.4	Withholding	A-48
Section 9.5	Election to be Treated as a Corporation	A-48

Article X ADMISSION OF PARTNERS		A-48

Section 10.1	Admission of Limited Partners	A-48
Section 10.2	Admission of Successor General Partner	A-49
Section 10.3	Amendment of Agreement and Certificate of Limited Partnership	A-49

Article XI WITHDRAWAL OR REMOVAL OF PARTNERS		A-49

Section 11.1	Withdrawal of the General Partner	A-49
Section 11.2	Removal of the General Partner	A-51
Section 11.3	Interest of Departing General Partner and Successor General Partner	A-51
Section 11.4	Withdrawal of Limited Partners	A-52

Article XII DISSOLUTION AND LIQUIDATION		A-52

Section 12.1	Dissolution	A-52
Section 12.2	Continuation of the Business of the Partnership After Dissolution	A-53
Section 12.3	Liquidator	A-53
Section 12.4	Liquidation	A-54
Section 12.5	Cancellation of Certificate of Limited Partnership	A-54
Section 12.6	Return of Contributions	A-54
Section 12.7	Waiver of Partition	A-54
Section 12.8	Capital Account Restoration	A-54

Article XIII AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE		A-55

Section 13.1	Amendments to be Adopted Solely by the General Partner	A-55
Section 13.2	Amendment Procedures	A-56
Section 13.3	Amendment Requirements	A-56

A-ii


Section 13.4	Special Meetings	A-57
Section 13.5	Notice of a Meeting	A-57
Section 13.6	Record Date	A-57
Section 13.7	Postponement and Adjournment	A-58
Section 13.8	Waiver of Notice; Approval of Meeting	A-58
Section 13.9	Quorum and Voting	A-58
Section 13.10	Conduct of a Meeting	A-59
Section 13.11	Action Without a Meeting	A-59
Section 13.12	Right to Vote and Related Matters	A-59

Article XIV MERGER, CONSOLIDATION OR CONVERSION		A-60

Section 14.1	Authority	A-60
Section 14.2	Procedure for Merger, Consolidation or Conversion	A-60
Section 14.3	Approval by Limited Partners	A-61
Section 14.4	Certificate of Merger or Certificate of Conversion	A-63
Section 14.5	Effect of Merger, Consolidation or Conversion	A-63

Article XV RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS		A-64

Section 15.1	Right to Acquire Limited Partner Interests	A-64

Article XVI GENERAL PROVISIONS		A-65

Section 16.1	Addresses and Notices; Written Communications	A-65
Section 16.2	Further Action	A-65
Section 16.3	Binding Effect	A-65
Section 16.4	Integration	A-66
Section 16.5	Creditors	A-66
Section 16.6	Waiver	A-66
Section 16.7	Third-Party Beneficiaries	A-66
Section 16.8	Counterparts	A-66
Section 16.9	Applicable Law; Forum; Venue and Jurisdiction; Waiver of Trial by Jury	A-66
Section 16.10	Invalidity of Provisions	A-67
Section 16.11	Consent of Partners	A-67
Section 16.12	Facsimile and Email Signatures	A-67

A-iii

SEVENTH AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF TXO ENERGY PARTNERS

SEVENTH AMENDED AND RESTATED AGREEMENT OF

LIMITED PARTNERSHIP OF TXO ENERGY PARTNERS, L.P.

THIS SEVENTH AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF TXO ENERGY PARTNERS, L.P. dated as of January 31, 2023, is entered into by and between TXO ENERGY GP, LLC, a Delaware limited liability company, as the General Partner, and MORNINGSTAR PARTNERS II, L.P., a Delaware limited partnership, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Adjusted Capital Account” means, with respect to any Partner, the balance in such Partner’s Capital Account at the end of each taxable period of the Partnership, after giving effect to the following adjustments:

(a) credit to such Capital Account any amounts that such Partner is (x) obligated to restore under the standards set by Treasury Regulations Section 1.704-1(b)(2)(ii)(c) or (y) deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulations Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

(b) debit to such Capital Account the items described in Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and 1.704-1(b)(2)(ii)(d)(6).

The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulations Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.4(d).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of (a) a Contributed Property means the fair market value of such property or other consideration at the time of contribution and (b) an Adjusted Property means the fair market value of such

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Adjusted Property on the date of the Revaluation Event, in each case as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this Seventh Amended and Restated Agreement of Limited Partnership of TXO Energy Partners, L.P., as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest, (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity, and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of:

(i) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter;

(ii) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) resulting from dividends or distributions received after the end of such Quarter from equity interests in any Person other than a Subsidiary in respect of operations conducted by such Person during such Quarter; and

(iii) if the General Partner so determines, all or any portion of additional cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings after the end of such Quarter, less;

(b) the amount of any cash reserves established by the General Partner (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to:

(i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures, future acquisitions and anticipated future debt service requirements of the Partnership Group) subsequent to such Quarter;

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distribution under Section 6.3 in respect of any one or more of the next four Quarters;

provided, however, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

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Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means the board of directors or board of managers of the General Partner, if the General Partner is a corporation or limited liability company, or the board of directors or board of managers of the general partner of the General Partner, if the General Partner is a limited partnership, as applicable.

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for U.S. federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.4. The “Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions).

“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, Simulated Depletion, amortization and other cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property and (b) with respect to any other Partnership property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination. In the case of any oil and gas property (as defined in Section 614 of the Code), adjusted basis shall be determined pursuant to Treasury Regulations Section 1.613A-3(e)(3)(iii)(C). The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable to the Partnership or any Limited Partner for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means a certificate, in such form (including global form if permitted by applicable rules and regulations) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more classes of Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.3, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“Claim” (as used in Section 7.13(g)) has the meaning given such term in Section 7.13(g).

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“Closing Date” means the first date on which Common Units are sold by the Partnership to the IPO Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, as reported on the principal National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day, or if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by any quotation system then in use with respect to such Limited Partner Interests, or, if on any such day such Limited Partner Interests are not quoted by any such system, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” has the meaning given such term in Section 11.3(a).

“Commission” means the United States Securities and Exchange Commission.

“Common Unit” means a Limited Partner Interest having the rights and obligations specified with respect to Common Units in this Agreement.

“Conflicts Committee” means a committee of the Board of Directors composed of two or more directors, each of whom (a) is not an officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner (other than Group Members), (c) is not a holder of any ownership interest in the General Partner or its Affiliates or any Group Member other than (i) Common Units and (ii) awards that are granted to such director in his or her capacity as a director under any long-term incentive plan, equity compensation plan or similar plan implemented by the General Partner or the Partnership and (d) is determined by the Board of Directors to be independent under the independence standards for directors who serve on an audit committee of a board of directors established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading (or if the Common Units are not listed or admitted to trading, the New York Stock Exchange).

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property or other asset shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of January 31, 2023, among the Partnership, the General Partner and Holdings, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(c)(xi).

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“Current Market Price” means, as of any date, for any class of Limited Partner Interests, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

“Derivative Partnership Interests” means any options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative securities relating to, convertible into or exchangeable for Partnership Interests.

“Designated Individual” has the meaning given such term in Section 9.3(a).

“Economic Risk of Loss” has the meaning set forth in Treasury Regulations Section 1.752-2(a).

“Eligibility Certificate” has the meaning set forth in Section 4.8.

“Eligibility Trigger” has the meaning set forth in Section 4.8.

“Eligible Holder” means a Person that satisfies the eligibility requirements established by the General Partner for Partners pursuant to Section 4.8.

“Event Issue Value” means, with respect to any Common Unit as of any date of determination, (i) in the case of a Revaluation Event that includes the issuance of Common Units pursuant to a public offering and solely for cash, the price paid for such Common Units or (ii) in the case of any other Revaluation Event, the Closing Price of the Common Units on the date of such Revaluation Event or, if the General Partner determines that a value for the Common Unit other than such Closing Price more accurately reflects the Event Issue Value, the value determined by the General Partner.

“Event of Withdrawal” has the meaning given such term in Section 11.1(a).

“Excess Distribution” has the meaning given such term in Section 6.1(c)(iii).

“Excess Distribution Unit” has the meaning given such term in Section 6.1(c)(iii).

“Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute.

“General Partner” means TXO Energy GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in their capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the non-economic management interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), and includes any and all rights, powers and benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement. The General Partner Interest does not include any rights to receive distributions of Available Cash or distributions upon the dissolution and liquidation or winding-up of the Partnership.

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“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulations Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction.

“Group” means two or more Persons that, with or through any of their respective Affiliates or Associates, have any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power over or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, in each case, as such may be amended, supplemented or restated from time to time.

“Holder” means any of the following:

(a) the General Partner who is the Record Holder of Registrable Securities;

(b) any Affiliate of the General Partner who is the Record Holder of Registrable Securities (other than natural persons who are Affiliates of the General Partner by virtue of being officers, directors or employees of the General Partner or any of its Affiliates);

(c) any Person who has been the General Partner within the prior two years and who is the Record Holder of Registrable Securities;

(d) any Person who has been an Affiliate of the General Partner within the prior two years and who is the Record Holder of Registrable Securities (other than natural persons who were Affiliates of the General Partner by virtue of being officers, directors or employees of the General Partner or any of its Affiliates); and

(e) a transferee and current Record Holder of Registrable Securities to whom the transferor of such Registrable Securities, who was a Holder at the time of such transfer, assigns its rights and obligations under this Agreement; provided such transferee agrees in writing to comply with all applicable requirements and obligations in connection with the registration and disposition of such Registrable Securities pursuant to Section 7.13.

“Holdings” means MorningStar Partners II, L.P., a Delaware limited partnership.

“Indemnified Persons” has the meaning given such term in Section 7.13(g).

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of (i) any Group Member, the General Partner or any Departing General Partner or (ii) any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or

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any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as a manager, managing member, general partner, director, officer, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided, however, that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement because such Person’s status, service or relationship exposes such Person to potential claims, demands, suits or proceedings relating to the Partnership Group’s business and affairs.

“Ineligible Holder” means a Limited Partner who is not an Eligible Holder.

“Initial Public Offering” means the initial offering and sale of Common Units to the public (including the offer and sale of Common Units pursuant to the Underwriters’ Option), as described in the IPO Registration Statement.

“IPO Registration Statement” means the Registration Statement on Form S-1 (File No. 333-268424) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Public Offering.

“IPO Underwriter” means each Person named as an underwriter in Schedule 1 to the Underwriting Agreement who purchases Common Units pursuant thereto.

“Joint Venture” means a joint venture that is not a Subsidiary and through which a Group Member conducts its business and operations and in which such Group Member owns an equity interest.

“Joint Venture Agreement” means the joint venture agreement or similar governing document of any Joint Venture as such may be amended, supplemented or restated from time to time.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Limited Partner” means, unless the context otherwise requires, each existing Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership.

“Limited Partner Interest” means an ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units or other Partnership Interests (other than a General Partner Interest) or a combination thereof (but excluding Derivative Partnership Interests), and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner pursuant to the terms and provisions of this Agreement.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (d) of the third sentence of Section 12.1, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected pursuant to Section 12.3 to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Merger Agreement” has the meaning given such term in Section 14.1.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Exchange Act (or any successor to such Section).

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“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property or other consideration reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property or other consideration is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case as determined and required by the Treasury Regulations promulgated under Section 704(b) of the Code.

“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain for such taxable period over the Partnership’s items of loss and deduction for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain (as provided in Section 6.1(d)(iii)), but shall not include Simulated Depletion, Simulated Loss or any items specially allocated under Section 6.1(c).

“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction for such taxable period over the Partnership’s items of income and gain for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gain (as provided in Section 6.1(d)(iii)), but shall not include Simulated Depletion, Simulated Loss or any items specially allocated under Section 6.1(c).

“Noncompensatory Option” has the meaning set forth in Treasury Regulations Section 1.721-2(f).

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulations Section 1.704-2(b)(1), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulations Section 1.752-1(a)(2).

“Notice” means a written request from a Holder pursuant to Section 7.13 which shall (i) specify the Registrable Securities intended to be registered, offered and sold by such Holder, (ii) describe the nature or method of the proposed offer and sale of Registrable Securities, and (iii) contain the undertaking of such Holder to provide all such information and materials and take all action as may be required or appropriate in order to permit the Partnership to comply with all applicable requirements and obligations in connection with the registration and disposition of such Registrable Securities pursuant to Section 7.13.

“Notice of Election to Purchase” has the meaning given such term in Section 15.1(b).

“Operating Company” means MorningStar Operating LLC, a Delaware limited liability company, and any successors thereto.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to, or the general counsel or other inside counsel of, the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner or to such other Person selecting such counsel or obtaining such opinion.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the IPO Underwriters upon exercise of the Underwriters’ Option.

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“Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding in the Register as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Interests of any class then Outstanding, none of the Partnership Interests owned by or for the benefit of such Person or Group shall be entitled to be voted on any matter or be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Partnership Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding, directly or indirectly, from a Person or Group described in clause (i) provided, however, that, upon or prior to such acquisition, the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership with the prior approval of the Board of Directors.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulations Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulations Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulations Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means TXO Energy Partners, L.P., a Delaware limited partnership.

“Partnership Group” means, collectively, the Partnership and its Subsidiaries.

“Partnership Interest” means any class or series of equity interest in the Partnership (or, in the case of the General Partner Interest, a management interest), which shall include any Limited Partner Interests and the General Partner Interest but shall exclude any Derivative Partnership Interests.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulations Sections 1.704-2(b)(2) and 1.704-2(d).

“Percentage Interest” means, as of any date of determination, (a) as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of Units held by such Unitholder, by (B) the total number of Outstanding Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.5, the percentage established as part of such issuance. The Percentage Interest with respect to the General Partner Interest shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, estate, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Plan of Conversion” has the meaning given such term in Section 14.1.

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“Privately Placed Units” means any Common Units issued for cash or property other than pursuant to a public offering.

“Prior General Partner” means MorningStar Oil & Gas, LLC, a Delaware limited liability company.

“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests, (c) when used with respect to Holders who have requested to include Registrable Securities in a Registration Statement pursuant to Section 7.13(a) or 7.13(b), apportioned among all such Holders in accordance with the relative number of Registrable Securities held by each such holder and included in the Notice relating to such request.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership which includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to receive notice of, or entitled to exercise rights in respect of, any lawful action of Limited Partners (including voting) or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) with respect to any class of Partnership Interests for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the Partnership’s close of business on a particular Business Day or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered in the Register as of the Partnership’s close of business on a particular Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

“Register” has the meaning given such term in Section 4.5(a) of this Agreement.

“Registrable Security” means any Partnership Interest other than the General Partner Interest; provided, however, that any Registrable Security shall cease to be a Registrable Security (a) at the time a Registration Statement covering such Registrable Security is declared effective by the Commission or otherwise becomes effective under the Securities Act, and such Registrable Security has been sold or disposed of pursuant to such Registration Statement; (b) at the time such Registrable Security has been disposed of pursuant to Rule 144 (or any successor or similar rule or regulation under the Securities Act); (c) when such Registrable Security is held by a Group Member; and (d) at the time such Registrable Security has been sold in a private transaction in which the transferor’s rights under Section 7.13 of this Agreement have not been assigned to the transferee of such securities.

“Registration Statement” has the meaning given such term in Section 7.13(a) of this Agreement.

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“Required Allocations” means any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(c)(i), Section 6.1(c)(ii), Section 6.1(c)(iv), Section 6.1(c)(v), Section 6.1(c)(vi), Section 6.1(c)(vii) or Section 6.1(c)(ix).

“Revaluation Event” means an event that results in adjustment of the Carrying Value of each Partnership property pursuant to Section 5.4(d).

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time, and any successor to such statute.

“Selling Holder” means a Holder who is selling Registrable Securities pursuant to the procedures in Section 7.13 of this Agreement.

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with U.S. federal income tax principles set forth in Treasury Regulations Section 1.611-2(a)(1) (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulations Section 1.704-1(b) (2)(iv)(k)(2), applying the cost depletion method. For purposes of computing Simulated Depletion with respect to any oil and gas property (as defined in Section 614 of the Code), the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis. If the Carrying Value of an oil and gas property is adjusted pursuant to Section 5.4 during a taxable period, following such adjustment Simulated Depletion shall thereafter be calculated under the foregoing provisions based upon such adjusted Carrying Value.

“Simulated Gain” means the excess, if any, of the amount realized from the sale or other disposition of an oil or gas property (as defined in Section 614 of the Code) over the Carrying Value of such property and determined pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(k)(2).

“Simulated Loss” means the excess, if any, of the Carrying Value of an oil or gas property (as defined in Section 614 of the Code) over the amount realized from the sale or other disposition of such property and determined pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(k)(2).

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general partner of such partnership, but only if such Person, one or more Subsidiaries of such Person, or a combination thereof, controls such partnership on the date of determination; or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person. Notwithstanding anything to the contrary herein, for so long as any Person is not consolidated in the Partnership’s financial statements for accounting purposes, then such Person will not be deemed a “Subsidiary” of the Partnership or the Operating Company.

“Surviving Business Entity” has the meaning given such term in Section 14.2(b).

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“Tax Representative” has the meaning given such term in Section 9.3(a).

“Trading Day” means a day on which the principal National Securities Exchange on which the referenced Partnership Interests of any class are listed or admitted for trading is open for the transaction of business or, if such Partnership Interests are not listed or admitted for trading on any National Securities Exchange, a day on which banking institutions in New York City are not legally required to be closed.

“Transaction Documents” has the meaning given such term in Section 7.1(b).

“Transfer” has the meaning given such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the General Partner to act as registrar and transfer agent for any class of Partnership Interests in accordance with the Exchange Act and the rules of the National Securities Exchange on which such Partnership Interests are listed (if any); provided, however that, if no such Person is appointed as registrar and transfer agent for any class of Partnership Interests, the General Partner shall act as registrar and transfer agent for such class of Partnership Interests.

“Treasury Regulations” means the United States Treasury regulations promulgated under the Code.

“Underwriters’ Option” means the option to purchase additional Common Units granted to the IPO Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Underwriting Agreement” means that certain Underwriting Agreement dated as of January 26, 2023 among the IPO Underwriters, the Partnership and the General Partner providing for the purchase of Common Units by the IPO Underwriters.

“Underwritten Offering” means (a) an offering pursuant to a Registration Statement in which Partnership Interests are sold to an underwriter on a firm commitment basis for reoffering to the public (other than the Initial Public Offering), (b) an offering of Partnership Interests pursuant to a Registration Statement that is a “bought deal” with one or more investment banks, and (c) an “at-the-market” offering pursuant to a Registration Statement in which Partnership Interests are sold to the public through one or more investment banks or managers on a best efforts basis.

“Unit” means a Partnership Interest that is designated by the General Partner as a “Unit” and shall include Common Units but shall not include the General Partner Interest.

“Unit Majority” means at least a majority of the Outstanding Common Units.

“Unitholders” means the Record Holders of Units.

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d)).

“Unrestricted Person” means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing

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General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an “Unrestricted Person” for purposes of this Agreement from time to time.

“U.S. GAAP” means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

“Withdrawal Opinion of Counsel” has the meaning given such term in Section 11.1(b).

“Working Capital Borrowings” means borrowings incurred pursuant to a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to the Partners; provided, however that when such borrowings are incurred it is the intent of the borrower to repay such borrowings within 12 months from the date of such borrowings other than from additional Working Capital Borrowings.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include,” “includes,” “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof,” “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement. The General Partner has the power to construe and interpret this Agreement and to act upon any such construction or interpretation. To the fullest extent permitted by law, any construction or interpretation of this Agreement by the General Partner and any action taken pursuant thereto and any determination made by the General Partner in good faith shall, in each case, be conclusive and binding on all Record Holders and all other Persons for all purposes.

ARTICLE II

ORGANIZATION

Section 2.1 Formation. The Partnership was formed as a limited partnership pursuant to the provisions of the Delaware Act and is hereby continued without dissolution. The General Partner and Holdings hereby amend and restate the Sixth Amended and Restated Agreement of Limited Partnership of the Partnership in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the Record Holder thereof for all purposes.

Section 2.2 Name. The name of the Partnership shall be “TXO Energy Partners, L.P.”. Subject to applicable law, the Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “LP,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1675 South State Street, Suite B, Dover, Delaware 19904, and the registered agent for service of process on the

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Partnership in the State of Delaware at such registered office shall be Capital Services, Inc. The principal office of the Partnership shall be located at 400 West 7th Street, Fort Worth, Texas 76102, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 400 West 7th Street, Fort Worth, Texas 76102, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, Joint Venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to further the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that, except in connection with action taken by the General Partner under Section 9.5, the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed). To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve the conduct by the Partnership of any business and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any Joint Venture Agreement or any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in determining whether to propose or approve the conduct by the Partnership of any business shall be permitted to do so in its sole and absolute discretion.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets. Title to the assets of the Partnership, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such assets of the Partnership or any portion thereof. Title to any or all assets of the Partnership may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees of the General Partner or its Affiliates, as the General Partner may determine. The General Partner hereby declares and warrants that any assets of the Partnership for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees of the General Partner or its Affiliates shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership or one or more of the Partnership’s designated Affiliates as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will

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provide for the use of such assets in a manner satisfactory to any successor General Partner. All assets of the Partnership shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such assets of the Partnership is held.

ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. No action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall be deemed to be participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) nor shall any such action affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to Section 7.6, but otherwise notwithstanding any provision of this Agreement, or any duty otherwise existing at law or in equity, each Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) Each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense:

(i) to obtain from the General Partner either (A) the Partnership’s most recent filings with the Commission on Form 10-K and any subsequent filings on Form 10-Q and 8-K or (B) if the Partnership is no longer subject to the reporting requirements of the Exchange Act, the information specified in, and meeting the requirements of, Rule 144A(d)(4) under the Securities Act or any successor or similar rule or regulation under the Securities Act (provided, however, that the foregoing materials shall be deemed to be available to a Limited Partner in satisfaction of the requirements of this Section 3.4(a)(i) if posted on or accessible through the Partnership’s or the Commission’s website);

(ii) to obtain a current list of the name and last known business, residence or mailing address of each Partner; and

(iii) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto.

(b) To the fullest extent permitted by law, the rights to information granted the Limited Partners pursuant to Section 3.4(a) replace in their entirety any rights to information provided for in Section 17-305(a) of the Delaware Act and each of the Partners and each other Person or Group who acquires an interest in Partnership Interests and each other Person bound by this Agreement hereby agrees to the fullest extent permitted

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by law that they do not have any rights as Partners, interest holders or otherwise to receive any information either pursuant to Sections 17-305(a) of the Delaware Act or otherwise except for the information identified in Section 3.4(a).

(c) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or regulation or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

(d) Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Partners, each other Person or Group who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person or Group.

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP

INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates. Owners of Partnership Interests and, where appropriate, Derivative Partnership Interests, shall be recorded in the Register and, when deemed appropriate by the General Partner, ownership of such interests shall be evidenced by a physical certificate or book entry notation in the Register. Notwithstanding anything to the contrary in this Agreement, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests and Derivative Partnership Interests, Partnership Interests and Derivative Partnership Interests shall not be evidenced by physical certificates. Certificates, if any, shall be executed on behalf of the General Partner on behalf of the Partnership by the Chief Executive Officer, President, Chief Financial Officer or any Senior Vice President or Vice President and the Secretary, any Assistant Secretary, or other authorized officer of the General Partner, and shall bear the legend set forth in Exhibit A hereto. The signatures of such officers upon a certificate may, to the extent permitted by law, be facsimiles. In case any officer who has signed or whose signature has been placed upon such certificate shall have ceased to be such officer before such certificate is issued, it may be issued by the Partnership with the same effect as if he were such officer at the date of its issuance. If a Transfer Agent has been appointed for a class of Partnership Interests, no Certificate for such class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that, if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. With respect to any Partnership Interests that are represented by physical certificates, the General Partner may determine that such Partnership Interests will no longer be represented by physical certificates and may, upon written notice to the holders of such Partnership Interests and subject to applicable law, take whatever actions it deems necessary or appropriate to cause such Partnership Interests to be registered in book entry or global form and may cause such physical certificates to be cancelled or deemed cancelled. The General Partner shall have the power and authority to make all such other rules and regulations as it may deem expedient concerning the issue, transfer and registration or replacement of Certificates.

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Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests or Derivative Partnership Interests as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued, if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner or the Transfer Agent.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, to the fullest extent permitted by law, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The names and addresses of Unitholders as they appear in the Register shall be the official list of Record Holders of the Partnership Interests for all purposes. The Partnership and the General Partner shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person or Group, regardless of whether the Partnership or the General Partner shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person or Group in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Person on the other, such representative Person shall be the Limited Partner with respect to such Partnership Interest upon becoming the Record Holder in accordance with Section 10.1(b) and have the rights and obligations of a Limited Partner hereunder as, and to the extent, provided herein, including Section 10.1(c).

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Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction by which the holder of a Partnership Interest assigns all or any part of such Partnership Interest to another Person who is or becomes a Partner as a result thereof, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void, and the Partnership shall have no obligation to effect any such transfer or purported transfer.

(c) Nothing contained in this Agreement shall be construed to prevent or limit a disposition by any stockholder, member, partner or other owner of the General Partner or any Limited Partner of any or all of such Person’s shares of stock, membership interests, partnership interests or other ownership interests in the General Partner or such Limited Partner and the term “transfer” shall not include any such disposition.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep, or cause to be kept by the Transfer Agent on behalf of the Partnership, one or more registers in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the registration and transfer of Limited Partner Interests, and any Derivative Partnership Interests as applicable, shall be recorded (the “Register”).

(b) The General Partner shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, however, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of this Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests for which a Transfer Agent has been appointed, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered. Upon the proper surrender of a Certificate, such transfer shall be recorded in the Register.

(c) Upon the receipt by the General Partner of proper transfer instructions from the Record Holder of uncertificated Partnership Interests, such transfer shall be recorded in the Register.

(d) By acceptance of the transfer of any Limited Partner Interests in accordance with this Section 4.5 and except as provided in Section 4.8, each transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) acknowledges and agrees to the provisions of Section 10.1(b).

(e) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.7, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law, including the Securities Act, Limited Partner Interests shall be freely transferable.

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(f) The General Partner and its Affiliates shall have the right at any time to transfer their Common Units to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(b), the General Partner may transfer all or any part of its General Partner Interest without the approval of any Limited Partner or any other Person.

(b) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) except in connection with action taken by the General Partner under Section 9.5, the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest owned by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Except as provided in Section 4.7(c), notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) except in connection with action taken by the General Partner under Section 9.5, cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously so treated or taxed). The Partnership may issue stop transfer instructions to any Transfer Agent in order to implement any restriction on transfer contemplated by this Agreement.

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership’s becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal income tax purposes (to the extent not previously so treated or taxed) or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) Except for Section 4.7(a), nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

Section 4.8 Eligibility Certifications; Ineligible Holders.

(a) If at any time the General Partner determines, with the advice of counsel, that any Group Member is subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or

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forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner or its owner(s) (a “Eligibility Trigger”); then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or appropriate to obtain such proof of the nationality, citizenship or other related status of the Limited Partners and, to the extent relevant, their owners as the General Partner determines to be necessary or appropriate to eliminate or mitigate the risk of cancellation or forfeiture of any properties or interests therein.

(b) Such amendments may include provisions requiring all Limited Partners to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as a Limited Partner (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Limited Partner who fails to furnish to the General Partner upon its request an Eligibility Certificate or other requested information related thereto within a reasonable period, or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Limited Partner or a transferee of a Limited Partner is an Ineligible Holder, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.9 or the General Partner may refuse to effect the transfer of the Limited Partner Interests to such transferee. In addition, the General Partner shall be substituted for any Limited Partner that is an Ineligible Holder as the Limited Partner in respect of the Ineligible Holder’s Limited Partner Interests.

(d) The General Partner shall, in exercising, or abstaining from exercising, voting rights in respect of Limited Partner Interests held by it on behalf of Ineligible Holders, distribute the votes or abstentions in the same manner and in the same ratios as the votes of Limited Partners (including the General Partner and its Affiliates) in respect of Limited Partner Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of its Limited Partner Interest (representing the right to receive its share of such distribution in kind).

(f) At any time after an Ineligible Holder can and does certify that it no longer is an Ineligible Holder, it may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Ineligible Holder not redeemed pursuant to Section 4.9, such Ineligible Holder be admitted as a Limited Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as Limited Partner and shall no longer constitute an Ineligible Holder, and the General Partner shall cease to be deemed to be the Limited Partner in respect of such Limited Partner Interests.

Section 4.9 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Limited Partner fails to furnish an Eligibility Certificate or any information requested within the period of time specified in amendments adopted pursuant to Section 4.8, or if upon receipt of such Eligibility Certificate or such other information the General Partner determines, with the advice of counsel, that a Limited Partner is an Ineligible Holder, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is not an Ineligible Holder or has transferred its Limited Partner Interests to a Person who is not an Ineligible Holder and who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at its last address designated in the Register by registered or certified

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mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificates evidencing the Redeemable Interests at the place specified in the notice) and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Limited Partner or its duly authorized representative shall be entitled to receive the payment (which payment may, for the avoidance of doubt, be in cash or by delivery of a promissory note in accordance with Section 4.9(a)(ii) above) for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Limited Partner or transferee at the place specified in the notice of redemption, of the Certificates evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.9 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee, agent or representative of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring its Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement and the transferor provides notice of such transfer to the General Partner. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided, however, that the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that such transferee is not an Ineligible Holder. If the transferee fails to make such certification within 30 days after the request, and, in any event, before the redemption date, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Contributions by the General Partner and its Affiliates.

(a) In connection with the Initial Public Offering and entry by the General Partner into this Agreement, prior to or on the Closing Date:

(i) the Prior General Partner formed the General Partner and contributed $1,000 in exchange for all of the interest in the General Partner;

(ii) the Board of Directors effectuated an internal restructuring pursuant to which each existing Limited Partner conveyed their existing Limited Partner Interests into Holdings in exchange for limited partner

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interests in Holdings, simultaneously therewith Holdings was admitted as a substitute limited partner of the Partnership, immediately following such admission the existing Limited Partners ceased to be limited partners of the Partnership and the Partnership was continued without dissolution;

(iii) the Prior General Partner assigned all of its general partner interests in the Partnership to the General Partner, simultaneously with such assignment the General Partner was admitted as a substitute general partner of the Partnership, immediately following such admission the Prior General Partner ceased to be a general partner of the Partnership and the Partnership was continued without dissolution;

(iv) the name of the Partnership was changed to “TXO Energy Partners, L.P.”;

(v) the Certificate of Limited Partnership of the Partnership was amended and restated pursuant to the provisions of Section 17-210 of the Delaware Act to (i) reflect the General Partner as the new general partner of the Partnership and (ii) reflect the change in the name of the Partnership to “TXO Energy Partners, L.P.”; and

(vi) Holdings’ existing limited partner interest in the Partnership was recapitalized as [ ⚫ ] Common Units pursuant to the Contribution Agreement and this Agreement.

(b) Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.2 Contributions by Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each IPO Underwriter contributed cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each IPO Underwriter, all as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Underwriters’ Option, each IPO Underwriter shall contribute cash to the Partnership on the Option Closing Date in exchange for the issuance by the Partnership of Common Units to each IPO Underwriter, all as set forth in the Underwriting Agreement.

(c) No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units issued to Holdings pursuant to Section 5.1 and (ii) the Common Units issued to the IPO Underwriters as described in subparagraphs (a) and (b) of this Section 5.2.

(d) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

Section 5.3 Interest and Withdrawal. No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon dissolution and winding up of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.4 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee, agent or representative in any case in which such nominee, agent or representative has furnished the identity of such beneficial owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulations

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Section 1.704-1(b)(2)(iv). The Capital Account shall in respect of each such Partnership Interest be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest, (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and (iii) the portion of any amount realized from the disposition of an oil and gas property that constitutes Simulated Gains allocated with respect to such Partnership Interest in accordance with Section 6.1(d)(iii) and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest, (y) all items of Partnership deduction and loss computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and (z) Simulated Depletion and Simulated Loss in accordance with Section 6.1(d)(ii).

(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, however, that:

(i) Solely for purposes of this Section 5.4 and except as otherwise determined by the General Partner, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement, Joint Venture Agreement or governing, organizational or similar documents) of all property owned by (x) any other Group Member that is classified as a partnership for U.S. federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) The computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made (x) except as otherwise provided in Treasury Regulations Section 1.704-1(b)(2)(iv)(m), without regard to any election under Section 754 of the Code that may be made by the Partnership and (y) as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes.

(iv) To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or Section 743(b) of the Code (including pursuant to Treasury Regulations Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(v) In the event the Carrying Value of Partnership property is adjusted pursuant to Section 5.4(d), any Unrealized Gain resulting from such adjustment shall be treated as an item of gain and any Unrealized Loss resulting from such adjustment shall be treated as an item of loss.

(vi) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

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(vii) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted tax basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.4(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined under the rules prescribed by Treasury Regulations Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment. Simulated Depletion shall be computed in accordance with the provisions of the definition of Simulated Depletion.

(viii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulations Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

(c) Except as otherwise provided in this Section 5.4(c), a transferee of a Partnership Interest shall succeed to a Pro Rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d) (i) In accordance with Treasury Regulations Sections 1.704-1(b)(2)(iv)(f) and 1.704-1(b)(2)(iv)(h)(2), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of a Noncompensatory Option, the issuance of Partnership Interests as consideration for the provision of services (including upon the lapse of a “substantial risk of forfeiture” with respect to a Unit), or the conversion of the Combined Interest to Common Units pursuant to Section 11.3(b), the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property; provided, however, that in the event of the issuance of a Partnership Interest pursuant to the exercise of a Noncompensatory Option where the right to share in Partnership capital represented by such Partnership Interest differs from the consideration paid to acquire and exercise such option, the Carrying Value of each Partnership property immediately after the issuance of such Partnership Interest shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property and the Capital Accounts of the Partners shall be adjusted in a manner consistent with Treasury Regulations Section 1.704-1(b)(2)(iv)(s); provided further, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, in the event of an issuance of a Noncompensatory Option to acquire a de minimis Partnership Interest or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests (or, in the case of a Revaluation Event resulting from the exercise of a Noncompensatory Option, immediately after the issuance of the Partnership Interest acquired pursuant to the exercise of such Noncompensatory Option) shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may first determine an aggregate value for the assets of the Partnership that takes into account the current trading price of the Common Units, the fair market value of all other Partnership Interests at such time and the amount of Partnership Liabilities. The General Partner may allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate). Absent a contrary determination by the General Partner, the aggregate fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a Revaluation Event shall be the value that would result in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value.

(ii) In accordance with Treasury Regulations Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual distribution to a Partner of any Partnership property (other than a distribution of cash that is not in

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redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property; provided, however, that in the event of a distribution to a Partner of a de minimis amount of Partnership property, the General Partner may determine that such an adjustment is unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of a distribution other than one made pursuant to Section 12.4, be determined in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

Section 5.5 Issuances of Additional Partnership Interests and Derivative Partnership Interests.

(a) The Partnership may issue additional Partnership Interests (other than General Partner Interests) and Derivative Partnership Interests for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest; (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by Certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and Derivative Partnership Interests pursuant to this Section 5.5, (ii) the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, (iii) reflecting admission of such additional Limited Partners in the Register as the Record Holders of such Limited Partner Interests and (iv) all additional issuances of Partnership Interests and Derivative Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests or Derivative Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or Derivative Partnership Interests or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.6 Limited Preemptive Right. Except as provided in this Section 5.6 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, up to the

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extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests.

Section 5.7 Splits and Combinations.

(a) Subject to Section 5.7(d), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted.

(b) Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice (or such shorter periods as required by applicable law). The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of Partnership Interests represented by Certificates, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.5(d) and this Section 5.7(d), each fractional Unit shall be rounded to the nearest whole Unit (with fractional Units equal to or greater than a 0.5 Unit being rounded to the next higher Unit).

Section 5.8 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Sections 17-303, 17-607 or 17-804 of the Delaware Act.

Section 5.9 Deemed Capital Contributions by Partners. Consistent with the provisions of Treasury Regulations Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then (a) such property shall be treated as having been contributed to the Partnership by such Partner and (b) immediately thereafter the Partnership shall be treated as having transferred such property to the employee or other service provider.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction and Simulated Gain (computed in accordance with Section 5.4(b)) for each taxable period shall be allocated among the Partners, and the Capital Accounts of the Partners shall be adjusted for Simulated Depletion and Simulated Loss, as provided herein below.

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(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(c) and Capital Account adjustments pursuant to Section 6.1(d)(ii), Net Income for each taxable period and all items of income, gain, loss and deduction and, to the extent provided in Section 6.1(d)(iii), Simulated Gain, taken into account in computing Net Income for such taxable period shall be allocated as follows:

(i) First, to the General Partner as necessary to eliminate any deficit balance in the General Partner’s Capital Account; and

(ii) The balance, if any, to all Unitholders, Pro Rata.

(b) Net Loss. After giving effect to the special allocations set forth in Section 6.1(c) and Capital Account adjustments pursuant to Section 6.1(d)(ii), Net Loss for each taxable period and all items of income, gain, loss and deduction and, to the extent provided in Section 6.1(d)(iii), Simulated Gain, taken into account in computing Net Loss for such taxable period shall be allocated as follows:

(i) First, to all Unitholders, Pro Rata; provided, however, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account); and

(ii) The balance, if any, 100% to the General Partner.

(c) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period in the following order:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulations Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(c), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(c) with respect to such taxable period (other than an allocation pursuant to Section 6.1(c)(vi) and Section 6.1(c)(vii)). This Section 6.1(c)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulations Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(c)(i)), except as provided in Treasury Regulations Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulations Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(c), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(c) and other than an allocation pursuant to Section 6.1(c)(i), Section 6.1(c)(vi) and Section 6.1(c)(vii) with respect to such taxable period. This Section 6.1(c)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulations Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations. If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to a Unit exceeds the

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amount of cash or the Net Agreed Value of property distributed with respect to another Unit (the amount of the excess, an “Excess Distribution” and the Unit with respect to which the greater distribution is paid, an “Excess Distribution Unit”), then there shall be allocated gross income and gain to each Unitholder receiving an Excess Distribution with respect to the Excess Distribution Unit until the aggregate amount of such items allocated with respect to such Excess Distribution Unit pursuant to this Section 6.1(c)(iii) for the current taxable period and all previous taxable periods is equal to the amount of the Excess Distribution.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustment, allocation or distribution described in Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, however, that an allocation pursuant to this Section 6.1(c)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(c)(iv) were not in this Agreement.

(v) Gross Income Allocation. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulations Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, however, that an allocation pursuant to this Section 6.1(c)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(c)(iv) and this Section 6.1(c)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulations Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss. This Section 6.1(c)(vii) is intended to comply with Treasury Regulations Section 1.704-2(i)(1) and shall be interpreted consistently therewith.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulations Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners Pro Rata.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulations Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts as a result of a distribution to a Partner in complete liquidation of such Partner’s interest in the Partnership, the amount of such adjustment to the Capital Accounts shall be treated

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as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis) taken into account pursuant to Section 5.4, and such item of gain, loss, Simulated Gain or Simulated Loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity; Changes in Law. For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(c)(x) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss, deduction, Simulated Depletion, Simulated Gains and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1 and Simulated Depletion and Simulated Loss had been included in the definition of Net Income and Net Loss. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. In exercising its discretion under this Section 6.1(c)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(c)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(c)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(c)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(c)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Equalization of Capital Accounts With Respect to Privately Placed Units. Unrealized Gain or Unrealized Loss deemed recognized as a result of a Revaluation Event shall first be allocated to the (A) Unitholders holding Privately Placed Units or (B) Unitholders holding Common Units (other than Privately Placed Units), Pro Rata, as applicable, to the extent necessary to cause the Capital Account in respect of each

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Privately Placed Unit then Outstanding to equal the Capital Account in respect of each Common Unit (other than Privately Placed Units) then Outstanding.

(xiii) Allocations Regarding Certain Payments Made to Employees and Other Service Providers. Consistent with the provisions of Treasury Regulations Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then any items of deduction or loss resulting from or attributable to such transfer shall be allocated to the Partner (or its successor) that made such transfer and was deemed to have contributed such property to the Partnership pursuant to Section 5.9.

(d) Simulated Basis; Simulated Depletion and Simulated Loss; Simulated Gain.

(i) Simulated Basis. For purposes of determining and maintaining the Partners’ Capital Accounts, (i) the initial Simulated Basis of each oil and gas property (as defined in Section 614 of the Code) of the Partnership shall be allocated among the Partners, Pro Rata and (ii) if the Carrying Value of an oil and gas property (as defined in Section 614 of the Code) is adjusted pursuant to Section 5.4(d), the Simulated Basis of such property (as adjusted to reflect the adjustment to the Carrying Value of such property), shall be allocated to the Partners, Pro Rata.

(ii) Simulated Depletion and Simulated Loss. For purposes of applying clause (z) of the second sentence of Section 5.4(a), Simulated Depletion and Simulated Loss with respect to each oil and gas property (as defined in Section 614 of the Code) of the Partnership shall reduce each Partner’s Capital Account in proportion to the manner in which the Simulated Basis of such property is allocated among the Partners pursuant to Section 6.1(d)(i).

(iii) Simulated Gain. For purposes of applying clause (iii) of the second sentence of Section 5.4(a), Simulated Gain for any taxable period shall be treated as included in either Net Income or Net Loss and allocated pursuant to Section 6.1(a) or Section 6.1(b), as appropriate.

Section 6.2 Allocations for Tax Purposes. Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss, deduction and amount realized shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss, deduction or amount realized is allocated pursuant to Section 6.1.

(a) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for U.S. federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(b), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) that is (i) a Contributed Property shall initially be allocated among the non-contributing Partners, Pro Rata, but not in excess of any such Partner’s share of Simulated Basis as determined pursuant to Section 6.1(d)(i), and (ii) not a Contributed Property or an Adjusted Property shall initially be allocated to the Partners in proportion to each such Partner’s share of Simulated Basis as determined pursuant to Section 6.1(d)(i). Further, for purposes of Treasury Regulations Sections 1.704-1(b)(2)(iv)(k)(2) and 1.704-1(b) (4)(iii), the amount realized on the disposition of any oil and gas property (as defined in Section 614 of the Code) of the Partnership shall be allocated (i) first to the Partners in an amount equal to the remaining Simulated Basis of such property in the same proportions as the Simulated Basis of such property was allocated among the Partners pursuant to Section 6.1(d)(i), and (ii) any remaining amount realized shall be allocated to the Partners in the same ratio as Simulated Gain from the disposition of such oil and gas property is allocated pursuant to Section 6.1(a) or Section 6.1(b). If there is an event described in Section 5.4(d), the General Partner shall reallocate the adjusted tax basis of each oil and gas property in a manner (i) consistent with the principles of Section 704(c) of the Code and (ii) that maintains the U.S. federal income tax fungibility of the Units.

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Each Partner shall separately keep records of his, her or its share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his, her or its gain or loss on the disposition of such property by the Partnership.

(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined to be appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(c)(x)); provided, however, that the General Partner shall apply “remedial allocation method” in accordance with the principles of Treasury Regulations Section 1.704-3(d) in all events. For purposes of applying the “remedial allocation method” to oil and gas properties (i) the amount by which any Partner’s Capital Account is adjusted for Simulated Depletion shall be treated as an amount of book depletion allocated to such Partner and (ii) the amount of cost depletion computed by such Partner under Section 613A(c)(7)(D) of the Code shall be treated as an amount of tax depletion allocated to such Partner.

(c) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulations Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(d) In accordance with Treasury Regulations Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(e) All items of income, gain, loss, deduction and credit recognized by the Partnership for U.S. federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(f) Each item of Partnership income, gain, loss and deduction, for U.S. federal income tax purposes, shall be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, that such items for the period beginning on the Closing Date and ending on the last day of the month in which the last Option Closing Date or the expiration of the Underwriters’ Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the

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Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such gain or loss is recognized for U.S. federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder, and the Partners hereby agree that any such methods selected by the General Partner are made by the “agreement of the Partners” within the meaning of Treasury Regulations Section 1.706-4(f).

(g) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee, agent or representative in any case in which such nominee, agent or representative has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

(h) If, as a result of an exercise of a Noncompensatory Option, a Capital Account reallocation is required under Treasury Regulations Section 1.704-1(b)(2)(iv)(s)(3), the General Partner shall make corrective allocations pursuant to Treasury Regulations Section 1.704-1(b)(4)(x).

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 60 days following the end of each Quarter (other than the fourth Quarter of each fiscal year), and within 90 days following the end of the fourth Quarter of each fiscal year, commencing with the Quarter ending on March 31, 2023, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to the holders of Common Units Pro Rata as of the Record Date selected by the General Partner. All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act and other applicable law, notwithstanding any other provision of this Agreement. For the avoidance of doubt, the General Partner Interest shall not be entitled to distributions made pursuant to this Section 6.3(a).

(b) Notwithstanding Section 6.3(a) (but subject to the penultimate sentence of Section 6.3(a)), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners, or as a general expense of the Partnership, as determined appropriate under the circumstances by the General Partner.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, but without limitation on the ability of the General Partner to

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delegate its rights and power to other Persons, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner in its capacity as such shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.4, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for Partnership Interests, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.4 and Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the business or operations of the Partnership Group, including through a Subsidiary or a Joint Venture; subject to Section 7.7(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of cash held by the Partnership;

(vii) the selection and dismissal of officers, employees, agents, internal and outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of assets and the making of loans to, any further limited or general partnerships, Joint Ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

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(xii) the entering into of listing agreements with any National Securities Exchange regarding some or all of the Limited Partner Interests, or the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.7);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of Derivative Partnership Interests;

(xiv) the undertaking of any action in connection with the Partnership’s participation in the management of any Group Member or Joint Venture;

(xv) the undertaking of any action to effectuate the provisions of Section 9.5 and Section 14.3(f); and

(xvi) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, any Joint Venture Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Record Holders and each other Person who may acquire an interest in a Partnership Interest or that is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Contribution Agreement and the other agreements described in or filed as exhibits to the IPO Registration Statement that are related to the transactions contemplated by the IPO Registration Statement (collectively, the “Transaction Documents”) (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements thereof entered into after the date such Person becomes bound by the provisions of this Agreement); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the IPO Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or are otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Section 9.5 or Article XV) shall not constitute a breach by the General Partner of any duty or any other obligation of any type whatsoever that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2 Replacement of Fiduciary Duties. Notwithstanding any other provision of this Agreement, to the extent that, at law or in equity, the General Partner or any other Indemnitee would have duties (including fiduciary duties) to the Partnership, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, all such duties (including fiduciary duties) are hereby eliminated, to the fullest extent permitted by law, and replaced with the duties or standards expressly set forth herein. The elimination of duties (including fiduciary duties) and replacement thereof with the duties or standards expressly set forth herein are approved by the Partnership, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement.

Section 7.3 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the

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State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.4 Restrictions on the General Partner’s Authority to Sell Assets of the Partnership Group. Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.5 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.5 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner, to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner or its Affiliates in connection with managing and operating the Partnership Group’s business and affairs (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.5 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.8. Any allocation of expenses to the Partnership by the General Partner in a manner consistent with its or its Affiliates’ past business practices shall be deemed to have been made in good faith.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Interests or Derivative Partnership Interests), or cause the Partnership to issue Partnership Interests or Derivative Partnership Interests in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates in each case for the benefit of officers, employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests or Derivative Partnership Interests that the General Partner or such Affiliates are obligated to provide to any officers, employees, consultants and directors pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests or Derivative Partnership Interests purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.5(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General

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Partner as permitted by this Section 7.5(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

(d) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

(e) The General Partner and its Affiliates may enter into an agreement to provide services to any Group Member for a fee or otherwise than for cost.

Section 7.6 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership, (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a Limited Partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the IPO Registration Statement, (B) the acquiring, owning or disposing of debt securities or equity interests in any Group Member or (C) the guarantee of, and mortgage, pledge or encumbrance of any or all of its assets in connection with, any indebtedness of any Group Member.

(b) Subject to the terms of Section 7.6(c), each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, any Joint Venture Agreement or the partnership relationship established hereby in any business ventures of any Unrestricted Person.

(c) Subject to the terms of Sections 7.6(a) and (b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.6 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any duty existing at law, in equity or otherwise, of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement or any duty existing at law or in equity, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person bound by this Agreement for breach of any duty existing at law, in equity or otherwise, by reason of the fact that such Unrestricted Person (including the General

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Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership, provided, however, that such Unrestricted Person does not engage in such business or activity using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units and/or other Partnership Interests acquired by them. The term “Affiliates” when used in this Section 7.6(d) with respect to the General Partner shall not include any Group Member.

Section 7.7 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.7(a) and Section 7.7(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

Section 7.8 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or omitting or refraining to act) in such capacity on behalf of or for the benefit of the Partnership; provided, however, that the Indemnitee shall not be indemnified and held harmless pursuant to this Agreement if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in bad faith or engaged in intentional fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.8 shall be available to any Indemnitee (other than a Group Member) with respect to any such Indemnitee’s obligations pursuant to the Transaction Documents. Any indemnification pursuant to this Section 7.8 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.8(a) in appearing at, participating in or defending any

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claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.8, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.8.

(c) The indemnification provided by this Section 7.8 shall be in addition to any other rights to which an Indemnitee may be entitled under this Agreement, any other agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.8, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.8(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.8 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.8 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.8 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, any Group Member Agreement, any Joint Venture Agreement, under the Delaware Act or any other law, rule or regulation or at

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equity, to the fullest extent allowed by law, no Indemnitee or any of its employees or Persons acting on its behalf shall be liable for monetary damages to the Partnership, the Partners, or any other Persons who have acquired interests in Partnership Interests or are bound by this Agreement, for losses sustained or liabilities incurred, of any kind or character, as a result of any act or omission of an Indemnitee or any of its employees or Persons acting on its behalf unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee or any of its employees or Persons acting on its behalf acted in bad faith or engaged in intentional fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful.

(b) The General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee or any of its employees or Persons acting on its behalf has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners or to any other Persons who have acquired a Partnership Interest or are otherwise bound by this Agreement, the General Partner and any other Indemnitee or any of its employees or Persons acting on its behalf acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership, the Limited Partners, or any other Persons who have acquired interests in the Partnership Interests or are bound by this Agreement for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.9 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.9 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.10 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless a lesser standard is otherwise expressly provided in this Agreement, any Group Member Agreement or any Joint Venture Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other hand, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any Joint Venture Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) determined by the Board of Directors to be on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) determined by the Board of Directors to be fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. Whenever the General Partner makes a determination to refer or not to refer any potential conflict of interest to the Conflicts Committee for Special Approval, to seek or not to seek Unitholder approval or to adopt or not to adopt a resolution or course of action that has not received Special Approval or Unitholder approval, then the General Partner shall be entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty or obligation whatsoever to the Partnership or any Limited Partner, and the General Partner shall not, to the fullest extent permitted by law, be required to act in good faith

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or pursuant to any other standard or duty imposed by this Agreement, any Group Member Agreement, any Joint Venture Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in making such determination or taking or declining to take such other action shall be permitted to do so in its sole and absolute discretion. If Special Approval is sought, then it shall be presumed that, in making its determination, the Conflicts Committee acted in good faith, and if the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above or that a director satisfies the eligibility requirements to be a member of the Conflicts Committee, then it shall be presumed that, in making its determination, the Board of Directors acted in good faith. In any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging any action or decision or determination by the Conflicts Committee with respect to any matter referred to the Conflicts Committee for Special Approval by the General Partner, any action by the Board of Directors in determining whether the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above or whether a director satisfies the eligibility requirements to be a member of the Conflicts Committee, the Person bringing or prosecuting such proceeding shall have the burden of overcoming the presumption that the Conflicts Committee or the Board of Directors, as applicable, acted in good faith. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the conflicts of interest described in the IPO Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement or any such duty.

(b) Whenever the General Partner or the Board of Directors, or any committee thereof (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any Affiliate of the General Partner causes the General Partner to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement, any Joint Venture Agreement or any other agreement, then, unless a lesser standard is expressly provided for in this Agreement, the General Partner, the Board of Directors or such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different duties or standards (including fiduciary duties or standards) imposed by this Agreement, any Group Member Agreement, any Joint Venture Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A determination or other action or inaction will conclusively be deemed to be in “good faith” for all purposes of this Agreement, if the Person or Persons making such determination or taking or declining to take such other action subjectively believe that the determination or other action or inaction is not adverse to the best interests of the Partnership Group; provided, however, that if the Board of Directors is making a determination or taking or declining to take an action pursuant to clause (iii) or clause (iv) of the first sentence of Section 7.10(a), then in lieu thereof, such determination or other action or inaction will conclusively be deemed to be in “good faith” for all purposes of this Agreement if the members of the Board of Directors making such determination or taking or declining to take such other action subjectively believe that the determination or other action or inaction meets the standard set forth in clause (iii) or clause (iv) of the first sentence of Section 7.10(a), as applicable.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement, any Joint Venture Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner, any other Person who acquires an interest in a Partnership Interest or any other Person bound by this Agreement, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any Joint Venture Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the Person or Persons making such determination or taking or declining to take such other action shall be permitted to do so in their

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sole and absolute discretion. By way of illustration and not of limitation, whenever the phrases “at its option,” “its sole and absolute discretion” or some variation of those phrases, are used in this Agreement, they indicate that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.

(d) The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a partnership.

(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of, or approve the sale or disposition of, any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.

(f) Except as expressly set forth in this Agreement or expressly required by the Delaware Act, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership, any Limited Partner, any other Person who acquires an interest in a Partnership Interest or any other Person bound by this Agreement and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners, the Partnership, such interest holders and such other Persons to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(g) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a general partner or managing member of a Group Member, to approve actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.10.

(h) For the avoidance of doubt, whenever the Board of Directors, any member of the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee) and any member of any such committee, the officers of the General Partner or any Affiliates of the General Partner (including any Person making a determination or acting for or on behalf of such Affiliate of the General Partner) make a determination on behalf of or recommendation to the General Partner, or cause the General Partner to take or omit to take any action, whether in the General Partner’s capacity as the General Partner or in its individual capacity, the standards of care applicable to the General Partner shall apply to such Persons, and such Persons shall be entitled to all benefits and rights (but not the obligations) of the General Partner hereunder, including eliminations, waivers and modifications of duties (including any fiduciary duties) to the Partnership, any of its Partners or any other Person who acquires an interest in a Partnership Interest or any other Person bound by this Agreement, and the protections and presumptions set forth in this Agreement.

Section 7.11 Other Matters Concerning the General Partner and Other Indemnitees.

(a) The General Partner and any other Indemnitee may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner and any other Indemnitee may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and

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any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner or such Indemnitee, respectively, reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.

Section 7.12 Purchase or Sale of Partnership Interests. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests or Derivative Partnership Interests. As long as Partnership Interests are held by any Group Member, such Partnership Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Interests for its own account, subject to the provisions of Articles IV and X.

Section 7.13 Registration Rights of the General Partner and its Affiliates.

(a) Demand Registration. Upon receipt of a Notice from any Holder at any time after the 180th day after the Closing Date, the Partnership shall file with the Commission as promptly as reasonably practicable a registration statement under the Securities Act (each, a “Registration Statement”) providing for the resale of the Registrable Securities identified in such Notice, which may, at the option of the Holder giving such Notice, be a Registration Statement that provides for the resale of the Registrable Securities from time to time pursuant to Rule 415 under the Securities Act. The Partnership shall not be required pursuant to this Section 7.13(a) to file more than one Registration Statement in any twelve-month period nor to file more than three Registration Statements in the aggregate. The Partnership shall use commercially reasonable efforts to cause such Registration Statement to become effective as soon as reasonably practicable after the initial filing of the Registration Statement and to remain effective and available for the resale of the Registrable Securities by the Selling Holders named therein until the earlier of (i) six months following such Registration Statement’s effective date and (ii) the date on which all Registrable Securities covered by such Registration Statement have been sold. In the event one or more Holders request in a Notice to dispose of Registrable Securities pursuant to a Registration Statement in an Underwritten Offering and such Holder or Holders reasonably anticipate gross proceeds from such Underwritten Offering of at least $30.0 million in the aggregate, the Partnership shall retain underwriters that are reasonably acceptable to such Selling Holders in order to permit such Selling Holders to effect such disposition through an Underwritten Offering; provided the Partnership shall have the exclusive right to select the bookrunning managers. The Partnership and such Selling Holders shall enter into an underwriting agreement in customary form that is reasonably acceptable to the Partnership and take all reasonable actions as are requested by the managing underwriters to facilitate the Underwritten Offering and sale of Registrable Securities therein. No Holder may participate in the Underwritten Offering unless it agrees to sell its Registrable Securities covered by the Registration Statement on the terms and conditions of the underwriting agreement and completes and delivers all necessary documents and information reasonably required under the terms of such underwriting agreement. In the event that the managing underwriter of such Underwritten Offering advises the Partnership and the Holder in writing that in its opinion the inclusion of all or some Registrable Securities would adversely and materially affect the timing or success of the Underwritten Offering, the amount of Registrable Securities that each Selling Holder requested be included in such Underwritten Offering shall be reduced on a Pro Rata basis to the aggregate amount that the managing underwriter deems will not have such material and adverse effect. Any Holder may withdraw from such Underwritten Offering by notice to the Partnership and the managing underwriter; provided such notice is delivered prior to the launch of such Underwritten Offering.

(b) Piggyback Registration. At any time after the 180th day after the Closing Date, if the Partnership shall propose to file a Registration Statement (other than pursuant to a demand made pursuant to Section 7.13(a)) for an offering of Partnership Interests for cash (other than an offering relating solely to an employee benefit

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plan, an offering relating to a transaction on Form S-4 or an offering on any registration statement that does not permit secondary sales), the Partnership shall notify all Holders of such proposal at least five Business Days before the proposed filing date. The Partnership shall use commercially reasonable efforts to include such number of Registrable Securities held by any Holder in such Registration Statement as each Holder shall request in a Notice received by the Partnership within two Business Days of such Holder’s receipt of the notice from the Partnership. If the Registration Statement about which the Partnership gives notice under this Section 7.13(b) is for an Underwritten Offering, then any Holder’s ability to include its desired amount of Registrable Securities in such Registration Statement shall be conditioned on such Holder’s inclusion of all such Registrable Securities in the Underwritten Offering; provided, however, that, in the event that the managing underwriter of such Underwritten Offering advises the Partnership and the Holder in writing that in its opinion the inclusion of all or some Registrable Securities would adversely and materially affect the timing or success of the Underwritten Offering, the amount of Registrable Securities that each Selling Holder requested be included in such Underwritten Offering shall be reduced on a Pro Rata basis to the aggregate amount that the managing underwriter deems will not have such material and adverse effect. In connection with any such Underwritten Offering, the Partnership and the Selling Holders involved shall enter into an underwriting agreement in customary form that is reasonably acceptable to the Partnership and take all reasonable actions as are requested by the managing underwriters to facilitate the Underwritten Offering and sale of Partnership Interests therein. No Holder may participate in the Underwritten Offering unless it agrees to sell its Registrable Securities covered by the Registration Statement on the terms and conditions of the underwriting agreement and completes and delivers all necessary documents and information reasonably required under the terms of such underwriting agreement. Any Holder may withdraw from such Underwritten Offering by notice to the Partnership and the managing underwriter; provided such notice is delivered prior to the launch of such Underwritten Offering. The Partnership shall have the right to terminate or withdraw any Registration Statement or Underwritten Offering initiated by it under this Section 7.13(b) prior to the effective date of the Registration Statement or the pricing date of the Underwritten Offering, as applicable.

(i) furnish to each Selling Holder (A) as far in advance as reasonably practicable before filing a Registration Statement or any supplement or amendment thereto, upon request, copies of reasonably complete drafts of all such documents proposed to be filed (including exhibits and each document incorporated by reference therein to the extent then required by the rules and regulations of the Commission), and provide each such Selling Holder the opportunity to object to any information pertaining to such Selling Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Selling Holder with respect to such information prior to filing a Registration Statement or supplement or amendment thereto, and (B) such number of copies of such Registration Statement and the prospectus included therein and any supplements and amendments thereto as such Persons may reasonably request in order to facilitate the public sale or other disposition of the Registrable Securities covered by such Registration Statement; provided, however, that the Partnership will not have any obligation to provide any document pursuant to clause (B) hereof that is available on the Commission’s website;

(ii) if applicable, use its commercially reasonable efforts to register or qualify the Registrable Securities covered by a Registration Statement under the securities or blue sky laws of such jurisdictions as the Selling Holders or, in the case of an Underwritten Offering, the managing underwriter, shall reasonably request; provided, however, that the Partnership will not be required to qualify generally to transact business in any jurisdiction where it is not then required to so qualify or to take any action that would subject it to general service of process in any jurisdiction where it is not then so subject;

(iii) promptly notify each Selling Holder and each underwriter, at any time when a prospectus is required to be delivered under the Securities Act, of (A) the filing of a Registration Statement or any prospectus or prospectus supplement to be used in connection therewith, or any amendment or supplement thereto, and, with respect to such Registration Statement or any post-effective amendment thereto, when the same has become

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effective; and (B) any written comments from the Commission with respect to any Registration Statement or any document incorporated by reference therein and any written request by the Commission for amendments or supplements to a Registration Statement or any prospectus or prospectus supplement thereto;

(iv) immediately notify each Selling Holder and each underwriter, at any time when a prospectus is required to be delivered under the Securities Act, of (A) the occurrence of any event or existence of any fact (but not a description of such event or fact) as a result of which the prospectus or prospectus supplement contained in a Registration Statement, as then in effect, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading (in the case of the prospectus contained therein, in the light of the circumstances under which a statement is made); (B) the issuance or threat of issuance by the Commission of any stop order suspending the effectiveness of a Registration Statement, or the initiation of any proceedings for that purpose; or (C) the receipt by the Partnership of any notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or blue sky laws of any jurisdiction. Following the provision of such notice, subject to Section 7.13(f), the Partnership agrees to, as promptly as practicable, amend or supplement the prospectus or prospectus supplement or take other appropriate action so that the prospectus or prospectus supplement does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances then existing and to take such other reasonable action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto; and

(v) enter into customary agreements and take such other actions as are reasonably requested by the Selling Holders or the underwriters, if any, in order to expedite or facilitate the disposition of the Registrable Securities, including the provision of comfort letters and legal opinions as are customary in such securities offerings.

(d) Suspension. Each Selling Holder, upon receipt of notice from the Partnership of the happening of any event of the kind described in Section 7.13(c)(iv), shall forthwith discontinue disposition of the Registrable Securities by means of a prospectus or prospectus supplement until such Selling Holder’s receipt of the copies of the supplemented or amended prospectus contemplated by such subsection or until it is advised in writing by the Partnership that the use of the prospectus may be resumed, and has received copies of any additional or supplemental filings incorporated by reference in the prospectus.

(e) Expenses. Except as set forth in an underwriting agreement for the applicable Underwritten Offering or as otherwise agreed between a Selling Holder and the Partnership, all costs and expenses of a Registration Statement filed or an Underwritten Offering that includes Registrable Securities pursuant to this Section 7.13 (other than underwriting discounts and commissions on Registrable Securities and fees and expenses of counsel and advisors to Selling Holders) shall be paid by the Partnership.

(f) Delay Right. Notwithstanding anything to the contrary herein, if the General Partner determines that the Partnership’s compliance with its obligations in this Section 7.13 would be detrimental to the Partnership because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone compliance with such obligations for a period of not more than six months; provided, however, that such right may not be exercised more than twice in any 24-month period.

(g) Indemnification.

(i) In addition to and not in limitation of the Partnership’s obligation under Section 7.8, the Partnership shall, to the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, indemnify and hold harmless each Selling Holder, its officers, directors and each Person who

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controls the Selling Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.13(g) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any Registration Statement, preliminary prospectus, final prospectus or issuer free writing prospectus under which any Registrable Securities were registered or sold by such Selling Holder under the Securities Act, or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such Registration Statement, preliminary prospectus, final prospectus or issuer free writing prospectus in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Selling Holder specifically for use in the preparation thereof.

(ii) Each Selling Holder shall, to the fullest extent permitted by law, indemnify and hold harmless the Partnership, the General Partner, the General Partner’s officers and directors and each Person who controls the Partnership or the General Partner (within the meaning of the Securities Act) and any agent thereof to the same extent as the foregoing indemnity from the Partnership to the Selling Holders, but only with respect to information regarding such Selling Holder furnished in writing by or on behalf of such Selling Holder expressly for inclusion in such Registration Statement, preliminary prospectus, final prospectus or free writing prospectus.

(iii) The provisions of this Section 7.13(g) shall be in addition to any other rights to indemnification or contribution that a Person entitled to indemnification under this Section 7.13(g) may have pursuant to under law, equity, contract or otherwise.

(h) Specific Performance. Damages in the event of breach of Section 7.13 by a party hereto may be difficult, if not impossible, to ascertain, and it is therefore agreed that each party, in addition to and without limiting any other remedy or right it may have, will have the right to seek an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and enforcing specifically the terms and provisions hereof, and each of the parties hereto hereby waives, to the fullest extent permitted by law, any and all defenses it may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right will not preclude any such party from pursuing any other rights and remedies at law or in equity that such party may have.

Section 7.14 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person (other than the General Partner and its Affiliates) dealing with the Partnership shall be entitled to assume that the General Partner and any officer or representative of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer or representative as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer or representative in connection with any such dealing. In no event shall any Person (other than the General Partner and its Affiliates) dealing with the General Partner or any such officer or representative be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or representative. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or such officer or representative shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this

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Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including the Register and all other books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the Register, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, however, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) Whether or not the Partnership is subject to the requirement to file reports with the Commission, as soon as practicable, but in no event later than 105 days after the close of each fiscal year of the Partnership (or such shorter period as required by the Commission), the General Partner shall cause to be mailed or made available, by any reasonable means (including by posting on or making accessible through the Partnership’s or the Commission’s website) to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner, and such other information as may be required by applicable law, regulation or rule of the Commission or any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(b) Whether or not the Partnership is subject to the requirement to file reports with the Commission, as soon as practicable, but in no event later than 50 days after the close of each Quarter (or such shorter period as required by the Commission) except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means (including by posting on or making accessible through the Partnership’s or the Commission’s website) to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of the Commission or any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

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ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for U.S. federal, state and local income tax purposes on the basis of the accrual method and the taxable period or year that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for U.S. federal and state income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable Treasury Regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies.

(a) Subject to the provisions hereof, the General Partner shall serve as the “partnership representative” within the meaning of Section 6223(a) of the Code (the “Tax Representative”). For each taxable year, the Tax Representative shall designate a “designated individual” within the meaning of Treasury Regulations Section 301.6223-1(b)(3) (the “Designated Individual”). The Tax Representative and the Designated Individual shall have, in their sole discretion, any and all authority as the “partnership representative” and “designated individual,” as the case may be, under the Code to act on behalf of the Partnership in any audit or tax-related examinations or administrative and judicial proceedings brought by taxing authorities, including, without limitation, (i) binding the Partnership and the Partners with respect to tax matters and (ii) determining whether to make any available election under Section 6226 of the Code. The Partnership and the Partners shall be bound by the actions taken by the Tax Representative or the Designated Individual in such capacity.

(b) The Partnership shall reimburse the Tax Representative and the Designated Individual for expenses incurred in connection with such Person’s discharge of its obligations as Tax Representative or Designated Individual, as appropriate.

(c) Each Partner agrees to (i) timely provide the Tax Representative or the Designated Individual with any information, statements or executed Internal Revenue Service forms reasonably requested by the Tax Representative or the Designated Individual and (ii) cooperate with the Tax Representative or the Designated Individual and to do or refrain from doing any or all things reasonably requested by the Tax Representative or Designated Individual (including paying any and all resulting taxes, additions to tax, penalties and interest in a timely fashion) in connection with any examination of the Partnership’s affairs by any federal, state or local tax authorities, including resulting administrative and judicial proceedings.

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Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code, or established under any foreign law. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 or Section 12.4(c) in the amount of such withholding from such Partner.

Section 9.5 Election to be Treated as a Corporation. Notwithstanding any other provision of this Agreement, if at any time the General Partner in good faith determines that the Partnership should no longer be characterized as a partnership for U.S. federal or applicable state and local income tax purposes, or that some or all of the Common Units should be converted into or exchanged for interests in a newly formed entity taxed as a corporation or an entity taxable at the entity level for U.S. federal (or applicable state and local) income tax purposes whose sole asset is Partnership Interests, then the General Partner may, without Limited Partner approval, take such steps, if any, as it determines are necessary or appropriate to (a) cause the Partnership to be treated as, or confirm that the Partnership will be treated as, an entity taxable as a corporation or as an entity taxable at the entity level for U.S. federal (or applicable state and local) income tax purposes, whether by election of the Partnership or conversion of the Partnership or by any other means or methods, or (b) cause some or all of the Common Units to be converted into or exchanged for interests in a newly formed entity taxable as a corporation or an entity taxable at the entity level for U.S. federal (or applicable state and local) income tax purposes whose sole asset is Partnership Interests. Each Limited Partner does hereby irrevocably constitute and appoint the General Partner, with full power of substitution, the true and lawful attorney-in-fact and agent of such Limited Partner, to execute, acknowledge, verify, swear to, deliver, record and file, in its or its assignee’s name, place and stead, all instruments, documents and certificates, and take any other actions, that may from time to time be necessary or appropriate to effectuate a transaction permitted by this Section 9.5, including without limitation any transaction to convert or otherwise reorganize the Partnership into a new limited liability entity, or to merge the Partnership with or into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations immediately prior to such conversion, merger, reorganization or conveyance. The foregoing power of attorney shall be irrevocable and is a power coupled with an interest and shall survive and not be affected by the subsequent death, disability, incapacity, dissolution, termination of existence or bankruptcy of, or any other event concerning, a Limited Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) Upon the issuance by the Partnership of Common Units to Holdings and the IPO Underwriters in connection with the Initial Public Offering as described in Article V, such Persons shall, by acceptance of such Partnership Interests, and upon becoming the Record Holders of such Partnership Interests, be admitted to the Partnership as Limited Partners in respect of the Common Units issued to them and be bound by this Agreement, all with or without execution of this Agreement by such Persons.

(b) By acceptance of any Limited Partner Interests transferred in accordance with Article IV or acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger, consolidation or conversion pursuant to Article XIV, and except as provided in Section 4.8, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee, agent or representative acquiring such Limited Partner Interests for the account of another Person or Group, which nominee, agent or representative shall be subject to Section 10.1(c) below) (i) shall be admitted to the Partnership as a Limited Partner with

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respect to the Limited Partner Interests so transferred or issued to such Person when such Person becomes the Record Holder of the Limited Partner Interests so transferred or acquired, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) shall be deemed to represent that the transferee or acquirer has the capacity, power and authority to enter into this Agreement and (iv) shall be deemed to make any consents, acknowledgements or waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and becoming the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.8.

(c) With respect to Units that are held for a Person’s account by another Person that is the Record Holder (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), such Record Holder shall, in exercising the rights of a Limited Partner in respect of such Units, including the right to vote, on any matter, and unless the arrangement between such Persons provides otherwise, take all action as a Limited Partner by virtue of being the Record Holder of such Units in accordance with the direction of the Person who is the beneficial owner of such Units, and the Partnership shall be entitled to assume such Record Holder is so acting without further inquiry. The provisions of this Section 10.1(c) are subject to the provisions of Section 4.3.

(d) The name and mailing address of each Record Holder shall be listed in the Register. The General Partner shall update the Register from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable).

(e) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(b).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to (a) the withdrawal or removal of the predecessor or transferring General Partner pursuant to Sections 11.1 or 11.2 or (b) the transfer of the General Partner Interest pursuant to Section 4.6; provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor is hereby authorized to and shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the Register and any other records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

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(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its General Partner Interest pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A) through (C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi) (A) if the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) if the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) if the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) if the General Partner is a natural person, his or her death or adjudication of incompetency; and (E) otherwise upon the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Time, on December 31, 2032 the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, however, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously so treated or taxed and except in connection with action taken by the General Partner under Section 9.5); (ii) at any time after 12:00 midnight, Central Time, on December 31, 2032 the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of

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record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal pursuant to Section 11.1(a)(i), a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Removal of the General Partner. The General Partner may only be removed if such removal is approved by the Unitholders holding at least 66 2/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by a Unit Majority (including Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units pursuant to Section 11.2 under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ general partner interest (or equivalent interest), if any, in the other Group Members (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders pursuant to Section 11.2 under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.5, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

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For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner, the value of the General Partner Interest and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

Section 11.4 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, Section 11.2 or Section 12.2, to the fullest extent permitted by law, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and a Withdrawal Opinion of Counsel is received as provided in Section 11.1(b) or 11.2 and such successor is admitted to the Partnership pursuant to Section 10.2;

(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

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(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Unitholders to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then, to the maximum extent permitted by law, within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the Departing General Partner, then the interest of the Departing General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, however, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner under the Delaware Act and (y) except in connection with action taken by the General Partner under Section 9.5, neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of such right to continue (to the extent not previously so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership in accordance with the provisions of Article XII, the General Partner (or in the event of dissolution pursuant to Section 12.1(a), the holders of a Unit Majority) shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by a Unit Majority. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a Unit Majority. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.4) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

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Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, satisfy its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts owed to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to satisfy liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulations Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from assets of the Partnership.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

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ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Limited Partner agrees that the General Partner, without the approval of any Limited Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for U.S. federal income tax purposes, except as provided in Section 9.5;

(d) a change that the General Partner determines (i) does not adversely affect the Limited Partners considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests in any material respect (except as permitted by Section 13.1(g)), (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.7 or Section 9.5 or (iv) is required to effect the intent expressed in the IPO Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable year of the Partnership and related changes, including a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that (i) sets forth the designations, preferences, rights, powers and duties of any class or series of Partnership Interests or Derivative Partnership Interests issued pursuant to Section 5.5 or (ii) the General Partner determines to be necessary or appropriate or advisable in connection with the authorization or issuance of any class or series of Partnership Interests or Derivative Partnership Interests pursuant to Section 5.5;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 9.5 or Section 14.3;

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(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, Joint Venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or Section 7.1(a);

(k) an amendment to Section 10.1 providing that any transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interest for the account of another Person) shall be deemed to certify that the transferee is an Eligible Holder;

(l) an amendment that the General Partner determines to be necessary or appropriate or advisable in connection with a merger, conveyance, conversion or other transaction or action pursuant to Section 9.5, Section 14.3(d), Section 14.3(e) or Section 14.3(f); or

(m) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Amendments to this Agreement may be proposed only by the General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so free of any duty or obligation whatsoever to the Partnership, any Limited Partner or any other Person bound by this Agreement, and, in declining to propose or approve an amendment to this Agreement, to the fullest extent permitted by law, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any Joint Venture Agreement, any other agreement contemplated hereby or otherwise or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in determining whether to propose or approve any amendment to this Agreement shall be permitted to do so in its sole and absolute discretion. An amendment to this Agreement shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 or Section 13.3, the holders of a Unit Majority, unless a greater or different percentage of Outstanding Units is required under this Agreement. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has posted or made accessible such amendment through the Partnership’s or the Commission’s website.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of (i) in the case of any provision of this Agreement other than Section 11.2 or Section 13.4, reducing such percentage or (ii) in the case of Section 11.2 or Section 13.4, increasing such percentages, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute (x) in the case of a reduction as described in subclause (a)(i) hereof, not less than the voting requirement sought to be reduced, (y) in the case of an increase in the percentage in Section 11.2, not less than 66 2/3% of the Outstanding Units, or (z) in the case of an increase in the percentage in Section 13.4, not less than a majority of the Outstanding Units.

(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c) or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or

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otherwise payable to, the General Partner or any of its Affiliates without the General Partner’s consent, which consent may be given or withheld in its sole discretion.

(c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Limited Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Sections 14.3(b) and (f), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4 Special Meetings. All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the specific purposes for which the special meeting is to be called and the class or classes of Units for which the meeting is proposed. No business may be brought by any Limited Partner before such special meeting except the business listed in the related request. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send or cause to be sent a notice of the meeting to the Limited Partners. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not be permitted to vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business. If any such vote were to take place, to the fullest extent permitted by law, it shall be deemed null and void to the extent necessary so as not to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1.

Section 13.6 Record Date. For purposes of determining the Limited Partners who are Record Holders of the class or classes of Limited Partner Interests entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11, the General Partner shall set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which such Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then

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(i) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (ii) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Postponement and Adjournment. Prior to the date upon which any meeting of Limited Partners is to be held, the General Partner may postpone such meeting one or more times for any reason by giving notice to each Limited Partner entitled to vote at the meeting so postponed of the place, date and hour at which such meeting would be held. Such notice shall be given not fewer than two days before the date of such meeting and otherwise in accordance with this Article XIII. When a meeting is postponed, a new Record Date need not be fixed unless the aggregate amount of such postponement shall be for more than 45 days after the original meeting date. Any meeting of Limited Partners may be adjourned by the General Partner one or more times for any reason, including the failure of a quorum to be present at the meeting with respect to any proposal or the failure of any proposal to receive sufficient votes for approval. No vote of the Limited Partners shall be required for any adjournment. A meeting of Limited Partners may be adjourned by the General Partner as to one or more proposals regardless of whether action has been taken on other matters. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting. The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after call and notice in accordance with Sections 13.4 and 13.5, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove of any matters submitted for consideration or to object to the failure to submit for consideration any matters required to be included in the notice of the meeting, but not so included, if such objection is expressly made at the beginning of the meeting.

Section 13.9 Quorum and Voting. The presence, in person or by proxy, of holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner and its Affiliates) entitled to vote at the meeting shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. Abstentions and broker non-votes in respect of such Units shall be deemed to be Units present at such meeting for purposes of establishing a quorum. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present for which no minimum or other vote of Limited Partners is required by any other provision of this Agreement, the rules or regulations of any National Securities Exchange on which the Common Units are admitted to trading, or applicable law or pursuant to any regulation applicable to the Partnership or its Partnership Interests, a majority of the votes cast by the Limited Partners holding Outstanding Units shall be deemed to constitute the act of all Limited Partners (with abstentions and broker non-votes being deemed to not have been cast with respect to such matter); provided that if a different percentage is required with respect to such action under the provisions of this Agreement, such rules or regulations of such National Securities Exchange(s), applicable law or pursuant to any such regulation, the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the exit of enough Limited Partners to leave less

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than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement.

Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the submission and revocation of approvals in writing.

Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units deemed owned by the General Partner and its Affiliates) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Outstanding Units held by such Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Outstanding Units that were not voted. If approval of the taking of any permitted action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) approvals sufficient to take the action proposed are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are first deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person that is the Record Holder (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), such Record Holder shall, in exercising the voting rights in respect of such Units on any matter, and

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unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and in accordance with the direction of, the Person who is the beneficial owner of such Units, and the Partnership shall be entitled to assume such Record Holder is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER, CONSOLIDATION OR CONVERSION

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general (including a limited liability partnership) or limited (including a limited liability limited partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America or any other country, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity, and the General Partner in determining whether to consent to any merger, consolidation or conversion of the Partnership shall be permitted to do so in its sole and absolute discretion.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) The name and state or country of domicile of each of the business entities proposing to merge or consolidate;

(ii) the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (A) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (B) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

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(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, however, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i) the names of the converting entity and the converted entity;

(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership;

(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the certificate of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, however, that if the effective time of the conversion is to be later than the date of the filing of such certificate of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and

(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Sections 14.3(d), (e) and (f), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent and, subject to any applicable requirements of Regulation 14A pursuant to the Exchange Act or successor provision, no other disclosure regarding the proposed merger, consolidation or conversion shall be required.

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(b) Except as provided in Sections 14.3(d), (e) and (f), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, effects an amendment to any provision of this Agreement that, if contained in an amendment to this Agreement adopted pursuant to Article XIII, would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.

(c) Except as provided in Sections 14.3(d), (e) and (f), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of limited liability under the laws of the jurisdiction governing the other limited liability entity (if that jurisdiction is not Delaware) of any Limited Partner as compared to its limited liability under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously treated as such and except in connection with action taken by the General Partner under Section 9.5), (ii) the primary purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the General Partner determines that the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially similar rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another limited liability entity if (i) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner under the laws of the jurisdiction governing the other limited liability entity (if that jurisdiction is not Delaware) as compared to its limited liability under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously treated as such and except in connection with action taken by the General Partner under Section 9.5), (ii) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (iii) the Partnership is the Surviving Business Entity in such merger or consolidation, (iv) each Unit Outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (v) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests Outstanding immediately prior to the effective date of such merger or consolidation.

(f) Notwithstanding anything else contained in this Agreement, the General Partner is further permitted, without Limited Partner approval, to convert or otherwise reorganize the Partnership into a new limited liability entity, or to merge the Partnership with or into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations immediately prior to such conversion, merger, reorganization or conveyance if the General Partner has determined that the conversion, merger, reorganization or conveyance would not result in the loss of limited liability of any Limited Partner (if that jurisdiction is not Delaware) as compared to such Limited Partner’s limited liability under the Delaware Act.

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(g) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (i) effect any amendment to this Agreement or (ii) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

Section 14.4 Certificate of Merger or Certificate of Conversion. Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion or other filing, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware or the appropriate filing office of any other jurisdiction, as applicable, in conformity with the requirements of the Delaware Act or other applicable law.

Section 14.5 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the merger or consolidation:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the conversion:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior Partners without any need for substitution of parties; and

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(vi) the Partnership Interests that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three Business Days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the applicable Transfer Agent or exchange agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent or exchange agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner), together with such information as may be required by law, rule or regulation, at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be filed and distributed as may be required by the Commission or any National Securities Exchange on which such Limited Partner Interests are listed. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests, in the case of Limited Partner Interests evidenced by Certificates, or instructions agreeing to such redemption in exchange for payment, at such office or offices of the Transfer Agent or exchange agent as the Transfer Agent or exchange agent, as applicable, may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at its address as reflected in the Register shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent or exchange agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate or redemption instructions shall not have been surrendered for purchase or provided, respectively, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent or the exchange agent of the Certificates representing such Limited Partner Interests, in the case of Limited Partner Interests evidenced by Certificates, or instructions agreeing to such redemption, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, in the Register, and the General Partner or any Affiliate of the General Partner,

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or the Partnership, as the case may be, shall be deemed to be the Record Holder of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the Record Holder of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI, and Article XII).

(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender its Certificate evidencing such Limited Partner Interest to the Transfer Agent or exchange agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon, in accordance with procedures set forth by the General Partner.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Except as otherwise provided herein, any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at its address as shown in the Register, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing in the Register is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in its address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing,” “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

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Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries. Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

Section 16.8 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) or (b) without execution hereof.

Section 16.9 Applicable Law; Forum; Venue and Jurisdiction; Waiver of Trial by Jury.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person or Group holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a duty (including any fiduciary duty) owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims; provided, however, that any claims, suits, actions or proceedings over which the Court of Chancery of the State of Delaware does not have jurisdiction shall be brought in any other court in the State of Delaware having jurisdiction; and provided further that this Section 16.9(b)(i) shall not apply to any claims as to which the Court of Chancery determines that there is an indispensable party not subject to the jurisdiction of such court, which is rested in the exclusive jurisdiction of a court or forum other than such court (including claims arising under the Exchange Act), or for which such court does not have subject matter jurisdiction, or to any claims arising under the Securities Act and, unless the Partnership consents in writing to the selection of an alternative forum, the United States federal district courts will be the sole and exclusive forum for resolving any action asserting a claim arising under the Securities Act;

(ii) irrevocably submits to the exclusive jurisdiction of such courts in connection with any such claim, suit, action or proceeding;

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(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of such courts or of any other court to which proceedings in such courts may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding;

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, however, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law; and

(vi) IRREVOCABLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING.

Section 16.10 Invalidity of Provisions. If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and/or parts thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision and/or part of such provision shall be reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Section 16.11 Consent of Partners. Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.12 Facsimile and Email Signatures. The use of facsimile signatures and signatures delivered by email in portable document format (.pdf) or similar format and any other electronic signatures affixed in the name and on behalf of the Transfer Agent of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.

[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.



GENERAL PARTNER: TXO ENERGY GP, LLC
GENERAL PARTNER: TXO ENERGY GP, LLC
By:
Name:
Title:

LIMITED PARTNER:

MORNINGSTAR PARTNERS II, L.P.

By:
Name:
Title:

Signature Page to First Amended and Restated

Agreement of Limited Partnership of TXO Energy Partners, L.P.

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EXHIBIT A

to the Seventh Amended and Restated

Agreement of Limited Partnership of

TXO Energy Partners, L.P.

Certificate Evidencing Common Units

Representing Limited Partner Interests in

TXO Energy Partners, L.P.

No. Common Units

In accordance with Section 4.1 of the Seventh Amended and Restated Agreement of Limited Partnership of TXO Energy Partners, L.P., as amended, supplemented or restated from time to time (the “Partnership Agreement”), TXO Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), hereby certifies that [____________] (the “Holder”) is the registered owner of [__]Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal executive offices of the Partnership located at 400 West 7th Street, Fort Worth, Texas 76102. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF TXO ENERGY PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE TRANSFERRED IF SUCH TRANSFER (AS DEFINED IN THE PARTNERSHIP AGREEMENT) WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF TXO ENERGY PARTNERS, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) EXCEPT IN CONNECTION WITH ACTION TAKEN BY THE GENERAL PARTNER UNDER SECTION 9.5 OF THE PARTNERSHIP AGREEMENT, CAUSE TXO ENERGY PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). THE GENERAL PARTNER OF TXO ENERGY PARTNERS, L.P. MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF, AT ANY TIME TXO ENERGY PARTNERS, L.P. IS NOT TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TAXED AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES, IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF TXO ENERGY PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES. THIS SECURITY MAY BE SUBJECT TO ADDITIONAL RESTRICTIONS ON ITS TRANSFER PROVIDED IN THE PARTNERSHIP AGREEMENT. COPIES OF SUCH AGREEMENT MAY BE OBTAINED AT NO COST BY WRITTEN REQUEST MADE BY THE HOLDER OF RECORD OF THIS SECURITY TO THE SECRETARY OF THE GENERAL PARTNER AT THE PRINCIPAL EXECUTIVE OFFICES OF THE PARTNERSHIP. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the

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Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, and (iii) made the waivers and given the consents and approvals contained in the Partnership Agreement.

If a Transfer Agent has been appointed, this Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent. This Certificate shall be governed by and construed in accordance with the laws of the State of Delaware.


Dated:	TXO Energy Partners, L.P.

	By:	TXO Energy GP, LLC

		By:

		By:


Countersigned and Registered by:

as Transfer Agent and Registrar

By:
		Authorized Signature

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[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:


TEN COM — as tenants in common	UNIF GIFT TRANSFERS MIN ACT

TEN ENT — as tenants by the entireties	Custodian
		(Cust)	(Minor)

JT TEN — as joint tenants with right of survivorship and not as tenants in common	under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

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ASSIGNMENT OF COMMON UNITS OF

TXO ENERGY PARTNERS, L.P.

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto





(Please print or typewrite name and address of assignee)		(Please insert Social Security or other identifying number of assignee)

Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of TXO Energy Partners, L.P.

Date: ____________		NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.

		(Signature)

		(Signature)

THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

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APPENDIX B

GLOSSARY OF OIL AND GAS TERMS AND OTHER TERMS

The terms and abbreviations defined in this section are used throughout this prospectus:

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGL.

“Boe.” One barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to one Bbl of oil.

“British Thermal Unit” or “Btu.” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed oil and gas reserves.” Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Existing Owners.” The holders of our existing equity interests.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Founders.” Bob R. Simpson, our Chief Executive Officer and Chairman, Brent W. Clum, our President of Business Operations, Chief Financial Officer and a Director, Keith A. Hutton, our President of Production and Development and a Director and Vaughn O. Vennerberg II, our former President.

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“Fracturing” or “fracture stimulation techniques.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“Gross acres or gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.

“Held by Production.” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“Injection Wells.” A well in which fluids are injected rather than produced, the primary objective typically being to maintain reservoir pressure.

“Lease operating expenses.” The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“MBbl.” One thousand barrels of crude oil, condensate or NGLs.

“MBoe.” One thousand Boe.

“Mcf.” One thousand cubic feet of natural gas.

“MMBoe.” One million Boe.

“MMBtu.” One million Btu.

“MMcf.” One million cubic feet of natural gas.

“Natural gas liquids (“NGLs”).” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“Net acres or net wells.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Net royalty acres.” Mineral ownership standardized to a 12.5%, or 1/8th, royalty interest.

“NYMEX.” The New York Mercantile Exchange.

“OPIS.” The Oil Price Information Service.

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“Possible reserves.” Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

“Probable reserves.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proved reserves.” Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that

B-3

renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

“Proved undeveloped reserves (“PUD”).” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

“PV-10.” When used with respect to oil and natural gas reserves, PV-10 represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Our PV-10 has historically been computed on the same basis as our standardized measure of discounted future net cash flows (the “Standardized Measure”), the most comparable measure under GAAP, but does not include a provision for either future well abandonment costs or the Texas gross margin tax. PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of either well abandonment costs or income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Standardized Measure.” Standardized Measure is our standardized measure of discounted future net cash flows, which is prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. No provision is included for federal income taxes since our future net cash flows are not subject to taxation. However, our operations are subject to the Texas franchise tax. Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as effected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.

B-4

“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

“Wellbore.” The hole drilled by the bit that is equipped for oil and natural gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil and natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

B-5

LOGO

TXO Energy Partners, L.P.

5,000,000 Common Units

Representing Limited Partner Interests

Prospectus

Joint Book-Running Managers


Raymond James		Stifel

Janney Montgomery Scott		Capital One Securities