10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 000-55916

Energy Resources 12, L.P.

(Exact name of registrant as specified in its charter) 

Delaware	81-4805237
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
120 W 3rd Street, Suite 220 Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

(817) 882-9192

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
None

Securities registered pursuant to Section 12(g) of the Exchange Act:

Common Units of Limited Partnership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐  No ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐  No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer   ☐	Accelerated filer ☐
Non-accelerated filer     ☐	Smaller reporting company   ☑
Emerging growth company   ☑

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☑

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

There is no established public market for the registrant’s outstanding limited partnership interests. The aggregate market value of the registrant’s limited partnership interests held by non-affiliates of the registrant as of June 30, 2020 was $0.

As of March 17, 2021, the Partnership had 11,031,579 common units outstanding.

Energy Resources 12, L.P.

Form 10-K

Index

		Page
Part I
	Item 1. Business	5
	Item 1A. Risk Factors	19
	Item 1B. Unresolved Staff Comments	34
	Item 2. Properties	34
	Item 3. Legal Proceedings	34
	Item 4. Mine Safety Disclosures	34
Part II
	Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	35
	Item 6. Selected Financial Data	37
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	Item 7A. Quantitative and Qualitative Disclosures about Market Risk	47
	Item 8. Financial Statements and Supplementary Data	48
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	66
	Item 9A. Controls and Procedures	66
	Item 9B. Other Information	66
Part III
	Item 10. Directors, Executive Officers and Corporate Governance	67
	Item 11. Executive Compensation	68
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	69
	Item 13. Certain Relationships and Related Transactions, and Director Independence	70
	Item 14. Principal Accounting Fees and Services	72
Part IV
	Item 15. Exhibits, Financial Statement Schedules	73
	Item 16. Form 10-K Summary	74
Signatures		75

Part I

FORWARD LOOKING STATEMENTS

Certain statements within this report may constitute forward-looking statements. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. You can identify these statements by the use of words such as “may,” “will,” “could,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “predict,” “continue,” “further,” “seek,” “plan” or “project” and variations of these words or comparable words or phrases of similar meaning.

These forward-looking statements include such things as:

• the easing of COVID-19 and the return to pre-existing supply and demand conditions following the ultimate recovery therefrom;

• intentions of the Partnership’s operators with regard to their drilling programs;

• references to future success in the Partnership’s drilling and marketing activities;

• the Partnership’s business strategy;

• estimated future capital expenditures;

• estimated future distributions;

• sales of the Partnership’s properties and other liquidity events;

• competitive strengths and goals; and

• other similar matters.

These forward-looking statements reflect the Partnership’s current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the Partnership’s control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under “Risk Factors” and the following:

• that the Partnership’s development of its oil and gas properties may not be successful or that its operations on such properties may not be successful;

• general economic, market, or business conditions;

• changes in laws or regulations;

• the risk that the wells in which the Partnership acquired an interest are productive, but do not produce enough revenue to return the investment made;

• the risk that the wells the Partnership drills do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected on the productive life of wells is shorter than expected;

• current credit market conditions and the Partnership’s ability to obtain long-term financing for its property acquisitions and drilling activities in a timely manner and on terms that are consistent with what the Partnership projects when it invests in a property;

• uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and

• the risk that any hedging policy the Partnership employs to reduce the effects of changes in the prices of its production will not be effective.

Although the Partnership believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, the Partnership cannot assure investors that its expectations will be attained or that any deviations will not be material. Investors are cautioned that forward-looking statements speak only as of the date they are made and that, except as required by law, the Partnership undertakes no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section.

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Item 1.  Business

Overview

Energy Resources 12, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

As of December 31, 2020, the Partnership owned an approximate 5.8% non-operated working interest in 372 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Partnership also owns an estimated approximate 1% non-operated working interest in 13 wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners.

The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). 

Business Objective

The Partnership’s primary investment objectives are to (i) acquire producing and non-producing oil and gas properties with development potential to be operated by third-party operators on-shore in the United States, and to enhance the value of the properties through drilling and other development activities, (ii) make distributions to the holders of the common units, (iii) engage in a liquidity transaction after five to seven years, in which all properties are sold and the sales proceeds are distributed to the partners, merge with another entity, or list the common units on a national securities exchange, and (iv) permit holders of common units to invest in oil and gas properties in a tax efficient basis. The proceeds from the sale of the common units primarily have been used to acquire the Bakken Assets and to develop these assets.

Investment and Drilling Activity

The Partnership acquired its non-operated working interests in the Bakken Assets during 2018 in two transactions. On February 1, 2018, the Partnership completed its first purchase in the Bakken Assets for $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership completed its second purchase in the Bakken Assets for $82.5 million, subject to customary adjustments.

From September 1, 2017, the effective date of the Partnership’s first acquisition, to December 31, 2020, the Partnership has participated in the drilling of 180 wells, of which 167 have been completed and the other 13 wells are in various stages of completion at December 31, 2020. The Partnership has incurred a total of approximately $56.4 million in capital drilling and completion costs to develop these 180 wells through December 30, 2020. The 13 wells in process at December 31, 2020 are expected to be completed during 2021, and the Partnership’s estimated share of capital expenditures to complete these 13 wells is approximately $0.4 million.

COVID-19, Demand, Pricing and Production

In December 2019, China reported an outbreak of a novel coronavirus (“COVID-19”) in its Wuhan province. COVID-19 rapidly spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy. On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States declared a national emergency with respect to COVID-19.

Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020 and remained depressed through the rest of 2020. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. These factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. NYMEX oil prices stabilized around $40 per barrel of oil in June 2020 and through the third quarter of 2020, and oil prices continued to increase through the fourth quarter of 2020, approaching $50 per barrel of oil in December 2020.

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In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs while also implementing other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. Certain operators of the Bakken Assets temporarily enacted some of these measures due to the inability to produce, process and sell oil and natural gas at economical prices; approximately 25% of the Partnership’s producing wells were shut in for at least a portion of the second quarter of 2020. While operators of the Bakken Assets have since returned significant inventory of existing wells to production, reduced sold production volumes and low commodity prices had a negative effect on the Partnership’s revenue and operating results during the second and third quarters of 2020. In addition, the Partnership’s operating results may be negatively impacted if new investment in the Partnership’s undrilled acreage remains limited while operators of the Bakken Assets wait for commodity prices and market supply and demand imbalances to become more favorable.

Industry Operating Environment

In addition to the specific global macroeconomic factors described above in “COVID-19, Demand, Pricing and Production”, the oil and natural gas industry is affected by other factors that the Partnership generally cannot control, including real or perceived geopolitical risks in oil-producing regions of the world, particularly the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by OPEC; and the strength of the U.S. dollar in international currency markets. Natural gas prices vary in accordance with North American supply and demand and are also affected by imports and exports of NGL. Weather also has a significant impact on demand for natural gas since it is a primary heating source in the United States.

Consistent with non-operators of well interests within the industry, the Partnership engages in oil and natural gas well development by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include the Partnership’s acreage. The Partnership relies on its operators to propose, permit and initiate the drilling of wells. The Partnership assesses each drilling opportunity on a case-by-case basis and participates in wells that expect to meet a desired return based upon estimates of recoverable oil and natural gas, expected oil and gas prices, expertise of the operator, and completed well cost from each project, as well as other factors.

The Partnership’ operators generally market and sell the oil and natural gas extracted from Partnership wells. In addition, these operators coordinate the transportation of oil and natural gas production from wells in which the Partnership participates to appropriate pipelines or rail transport facilities pursuant to arrangements that such operators negotiate and maintain with various parties purchasing the production. The price at which Partnership production is sold is generally tied to a market spot price, and the differential between the market spot price and the Partnership’s realized sales price represents the imbedded transportation costs in moving the oil from wellhead to refinery and will fluctuate based on availability of pipeline, rail and other transportation methods.

Production, Prices and Production Cost History

The following table sets forth certain information regarding the production volumes, average prices received, and average production costs associated with the sale of oil, natural gas, and natural gas liquids for the periods indicated below.

	Year Ended December 31,		Year Ended December 31,		Percent
	2020		2019		Change
Sold production (BOE):
Oil		853,633		1,129,951		-24.5	%
Natural gas		154,081		141,508		8.9	%
Natural gas liquids		141,483		126,760		11.6	%
Total		1,149,197		1,398,219		-17.8	%
Average sales price per unit:
Oil (per Bbl)	$	37.37	$	54.11		-30.9	%
Natural gas (per Mcf)		1.87		2.36		-20.8	%
Natural gas liquids (per Bbl)		9.03		10.09		-10.5	%
Combined (per BOE)		30.38		46.08		-34.1	%
Average unit cost per BOE:
Production costs
Production expenses		13.45		12.18		10.4	%
Production taxes		2.55		4.13		-38.4	%
Total production costs		15.99		16.31		-1.9	%
Depreciation, depletion, amortization and accretion		12.36		12.30		0.5	%

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Related Parties

The Partnership has, and is expected to continue to engage in, significant transactions with related parties, including those discussed below. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.

See further discussion in Note 8. Related Parties in Part II, Item 8 of this Form 10-K.

Partners’ Equity and Distributions

The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. David Lerner Associates, Inc. was the dealer manager for the Partnership’s best-efforts offering (the “Dealer Manager”). Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager also has Dealer Manager Incentive Fees (defined below), where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering based on the performance of the Partnership. Based on the common units sold in the offering, the Dealer Manager Incentive Fees are a maximum of approximately $8.7 million, subject to Payout (defined below).

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

The Partnership Agreement provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

For the year ended December 31, 2020, the Partnership paid distributions of $1.396165 per common unit, or $15.4 million. For the year ended December 31, 2019, the Partnership paid distributions of $1.396164 per common unit, or $13.3 million.

Oil and Natural Gas Reserves

The table below summarizes the Partnership’s estimated net proved reserves as of December 31, 2020:

	Oil		Natural Gas		NGLs		Total		Standardized Measure (2)
Proved Reserves (1)	(MBbls)		(MMcf)		(MBbls)		(MBOE)		(in thousands)
Developed		6,882		9,202		1,210		9,626	$	52,013
Undeveloped		10,184		7,777		1,014		12,494		16,000
Total Proved Reserves		17,066		16,979		2,224		22,120	$	68,013

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(1)	The following terms have been used by the Partnership to classify its reserves: Proved developed producing reserves (“PDP”) are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves (“PUD”) are reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development (reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled).
	The Partnership’s proved reserves as of December 31, 2020 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such date. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2020 were $39.57 per barrel of oil and $1.99 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2020 were $31.82 per barrel of oil, $(2.33) per MMcf of natural gas and $3.13 per barrel of NGL. See “Note 9 — Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this report for information concerning proved reserves.
(2)	The standardized measure of discounted future net cash flows represents the estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, in accordance with Accounting Standards Codification Topic 932 – Extractive Activities – Oil and Gas. Because the Partnership was formed as a limited partnership, the Partnership is not subject to federal taxes in the calculation of the standardized measure. In addition, there are no entity level or gross receipts taxes in North Dakota, where all Partnership wells are located, that would give rise to an additional state tax provision.

The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, the Partnership may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond its control. Prices for oil at December 31, 2020 were above the 2020 average prices using the parameters established by the SEC. Therefore, due to the volatility of the market, a period of sustained higher or lower prices will have a positive or negative impact to the estimated quantities and present values of the Partnership’s reserves.

Proved Undeveloped Reserves (PUD)

At December 31, 2020, the Partnership had PUDs of approximately 12,494 MBOE, or approximately 59% of total proved reserves. The following table reflects the changes in PUDs during 2020:

	BOE
Proved undeveloped reserves, December 31, 2019		12,517,645
Revisions of previous estimates (1)		697,585
Extensions, discoveries and other additions (2)		1,188,535
Conversion to proved developed reserves (3)		(1,909,530	)
Proved undeveloped reserves, December 31, 2020		12,494,235

(1)	The annual review of the PUDs resulted in a positive revision of approximately 698 MBOE. This revision was the result of 724 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2019, 21 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, and 5 MBOE of downward adjustments attributable to changes in the future drill schedule.
(2)	In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(3)	The Partnership converted 34 wells to proved developed reserves during 2020 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 1,909 MBOE.

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Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of their date of original booking unless specific circumstances justify a longer time. The Partnership will be required to remove current PUDs if the Partnership does not drill those reserves within the required five-year time frame, unless specific circumstances justify a longer time. The Partnership removed a portion of its PUDs during the second quarter of 2020 in conjunction with the significant drop in commodity prices caused by COVID-19 as the Partnership did not anticipate all PUD locations would be drilled within the five-year time frame. All of the Partnership’s PUDs at December 31, 2020 are scheduled to be drilled within five years of the date they were initially recorded. However, since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict with certainty the timing of drilling and completion of wells currently classified as PUD reserves. Historically, energy commodity prices have been volatile, and due to geopolitical risks in oil producing regions of the world as well as global supply and demand concerns, the Partnership continues to expect significant price volatility. Sustained lower prices for oil and natural gas may cause the Partnership in the future to forecast less capital to be available for development of its PUDs, which may cause the Partnership to decrease the number of PUDs it expects to develop within the five-year time frame. In addition, lower oil and natural gas prices may cause the Partnership’s PUDs to become uneconomic to develop, which would cause the Partnership to remove them from the proved undeveloped category.

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

The Partnership’s policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate its oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and the Partnership’s peers, and in accordance with the SPE 2007 Standards promulgated by the Society of Petroleum Engineers. The Partnership engaged Pinnacle Energy Services, LLC (“Pinnacle Energy”) to prepare the reserve estimates for all of the Partnership’s assets for the year ended December 31, 2020 in this annual report. Pinnacle Energy founder J.P. Dick has over 30 years of experience in the oil and natural gas industry, with exposure to reserves and reserve related valuations and issues during that time and is a Registered Professional Engineer in the states of Texas and Oklahoma. Further qualifications include a Bachelor of Science in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, Mr. Dick is an active participant in industry reserve seminars, professional industry groups and is a member of the Society of Petroleum Engineers.

The Partnership’s controls over reserve estimates include engaging Pinnacle Energy as the Partnership’s independent petroleum engineer. The Partnership provided information about its oil and natural gas properties, including production profiles, prices and costs, to Pinnacle Energy and they prepared estimates of the Partnership’s reserves attributable to the Partnership’s properties. All of the information regarding reserves in this annual report on Form 10-K is derived from the report of Pinnacle Energy, which is included as an exhibit to this annual report on Form 10-K.

The Partnership works closely with Pinnacle Energy to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process as well as to review properties and discuss the methods and assumptions used by Pinnacle Energy in their preparation of the year-end reserve estimates. The Partnership also reviews the methods and assumptions used by Pinnacle Energy in the preparation of year-end reserve estimates and assesses them for reasonableness. The Board of Directors of the General Partner also meets with Partnership management to discuss matters and policies related to the Partnership’s reserves.

The Partnership’s methodologies include reviews of production trends, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for proved undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields. The Partnership applies and maintains internal controls, including but not limited to the following, to ensure the reliability of reserves estimations:

● no employee’s compensation is tied to the amount of reserves booked;

● the Partnership follows comprehensive SEC-compliant internal policies to determine and report proved reserves;

● reserve estimates are made by experienced reservoir engineers or under their direct supervision;

● annual review by the Board of Directors of the General Partner of the Partnership’s year-end reserve estimates prepared by Pinnacle Energy; and

● semi-annually, the Board of Directors of the General Partner reviews all significant reserves changes and all new proved undeveloped reserves additions.

Total Productive Wells

The following table sets forth information with respect to the Partnership’s ownership interest in productive wells as of December 31, 2020:

	December 31, 2020
	Gross		Net
Oil wells:
Williston Basin, North Dakota		372		21.6

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Of the total well count for 2020, none are multiple completions.

Productive wells are producing wells and wells the Partnership deems mechanically capable of production, including shut-in wells, wells waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up. At December 31, 2020, the Partnership had 372 wells producing or capable of production and zero shut-in wells. A gross well is a well in which we own a working interest. The number of net wells represents the sum of fractional working interests the Partnership owns in gross wells.

Developed and Undeveloped Acreage Position

The following table sets forth information with respect to the Partnership’s gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2019, all of which is located in the State of North Dakota in the United States:

Acreage allocated to developed properties

Acreage allocated to undeveloped wellsites

Total Acres

Gross

Net

Gross

Net

Gross

Net

Williston Basin, North Dakota

5,861

2,457

2,664

1,117

8,525

3,574

As is customary in the oil and natural gas industry, the Partnership can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which the Partnership has an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, the Partnership is entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in developed leasehold acreage.

Undeveloped Acreage Expirations

The Partnership has no undeveloped acreage expirations as all acreage is held by production.

Delivery Commitments

As of December 31, 2020, the Partnership had no commitments to deliver a fixed quantity of oil or natural gas.

Marketing and Customers

The market for the Partnership’s oil and natural gas production depends on factors beyond its control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

The Partnership’s properties are operated by 14 third-party operators, who market and sell the Partnership’s production of oil, gas and natural gas liquids on behalf of the Partnership (and other fractional working interest owners).

Title to Properties

As is customary in the Partnership’s industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, was made at the time the Partnership acquired its properties. The Partnership believes that its title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in the Partnership’s operations. The interests owned by the Partnership may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Partnership’s operations.

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Insurance

Since the Partnership is not the operator of any of its properties, the Partnership primarily relies on the insurance of the operator(s) of its properties, of which the Partnership’s share of the cost is allocated back to the Partnership through the Joint Operating Agreement. The Partnership’s operators have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to its oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

The Partnership re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that the Partnership will be able to maintain insurance in the future at rates that the Partnership considers reasonable and the Partnership may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 

Competition

The oil and natural gas industry is highly competitive. The Partnership will encounter strong competition from independent oil and gas companies, master limited partnerships and from major oil and gas companies in contracting for drilling equipment and arranging the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than the Partnership’s.

The Partnership also may be affected by competition for drilling rigs, human resources and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. The Partnership is unable to predict when, or if, such shortages may occur or how they would affect the Partnership’s development and exploitation program.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit the Partnership’s drilling and producing activities and other operations in certain areas where the Partnership may acquire producing properties. These seasonal anomalies can pose challenges for meeting the Partnership’s drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay the Partnership’s operations. Generally, demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can lessen seasonal demand fluctuations.

Environmental, Health and Safety Matters and Regulation

The Partnership’s operations are subject to stringent and complex federal, state and local laws and regulations that govern the oil and natural gas industry, as well as regulations that protect the environment from the discharge of materials into the environment. These laws and regulations may, among other things:

● require the acquisition of various permits before drilling commences;

● require the installation of pollution control equipment in connection with operations;

● place restrictions or regulations upon the use or disposal of the material utilized in the Partnership’s operations;

● restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

● limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

● require remedial measures to mitigate or remediate pollution from former and ongoing operations, and may also require site restoration, pit closure and plugging of abandoned wells; and

● require the expenditure of significant amounts in connection with worker health and safety.

These laws, rules 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. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on the Partnership’s operating costs. In general, the oil and natural gas industry has been the subject of increased legislation and regulatory attention with respect to environmental matters. The trend of more expansive and stricter environmental regulation may continue for the long term.

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The following is a summary of some of the existing laws, rules and regulations to which the Partnership’s business operations are subject.

Solid and Hazardous Waste Handling

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, the Partnership expects its operators to generate waste as a routine part of their operations that may be subject to RCRA. Although a substantial amount of the waste expected to be generated is regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the Environmental Protection Agency (“EPA”) or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so-called potentially responsible parties, or PRPs, include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of the Partnership’s operators’ expected operations, the operators will generate wastes that may fall within CERCLA’s definition of hazardous substance and may dispose of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum, and there is no guarantee that federal law will not adopt more stringent requirements with respect to the petroleum substances. The Partnership may also be the owner of sites on which hazardous substances have been released. If contamination is discovered at a site on which the Partnership is or has been an owner or to which the Partnership sent hazardous substances, the Partnership could be liable for the costs of investigation and remediation and natural resources damages. Further, the Partnership could be required to suspend or cease operations in contaminated areas.

The Partnership may own producing properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances, wastes or hydrocarbons may have been released on or under the Partnership’s properties, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of the properties the Partnership has acquired may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under Partnership control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, the Partnership could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Clean Water Act

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, 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. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. Litigation surrounding this rule is ongoing. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, the Partnership may be liable for penalties and cleanup and response costs. The federal Clean Water Act only regulates surface waters. However, most of the state analogs to the Clean Water Act also regulate discharges which impact groundwater.

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In 2018, the EPA commenced a management study of oil and gas extraction wastewater from both conventional extraction and unconventional extraction such as hydraulic fracturing. The purpose of this study is to understand if support exists for new regulations that would allow for a broader discharge of oil and gas extraction wastewater directly to surface waters under the Clean Water Act’s National Pollutant Discharge Elimination System, in addition to the primary existing disposal methods of underground injection or discharge to centralized wastewater treatment facilities. The EPA produced a report of its findings in May 2020, which did not announce any new regulatory requirements regarding oil and gas extraction wastewater. In January 2021, the EPA published its final Effluent Guidelines Program Plan 14, its biennial plan for new and revised effluent limitations guidelines and standards for industrial wastewater discharges. Plan 14 discusses several ongoing regulatory actions, including upcoming revisions to increase flexibility for centralized waste treaters of produced water from oil and gas extraction.

Safe Drinking Water Act and Hydraulic Fracturing

Many of the properties the Partnership owns will require additional drilling operations to fully develop the reserves attributable to the properties. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel).

In prior sessions, Congress has considered legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. This legislation has not passed. A number of states, local and regional regulatory authorities have or are considering hydraulic fracturing regulation and other regulations imposing new or more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations or restricting or banning hydraulic fracturing. Further, the EPA has issued an effluent limitations guideline prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned treatment plants.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase the Partnership’s costs of compliance and business.

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where the Partnership owns properties that require additional drilling, the Partnership could incur substantial compliance costs and such requirements could adversely delay or restrict its ability to conduct fracturing activities on its assets. In December 2017, the Bureau of Land Management (“BLM”) rescinded its own rule from 2015 that would have required oil and gas companies to seek approval from BLM before conducting hydraulic fracturing operations on public lands and for companies to disclose the chemicals used in fracking fluid.

Oil Pollution Act

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water Act 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 United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns 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 to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge on properties it owns, the Partnership may be liable for costs and damages.

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Air Emissions

The operations of the Partnership’s operators are subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or seek injunctive relief, requiring the Partnership to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation. The EPA rules include standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards required owners/operators to reduce volatile organic compound, or VOC, emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of “green completions.” The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations established specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. In August 2020, the EPA finalized a rule that removed sources in the transmission and storage segment from regulation under the 2012 and 2016 New Source Performance Standards (“NSPS”) for the oil and natural gas industry for ozone-forming VOCs and for greenhouse gases (“GHGs”) from methane.

In 2016, the EPA had expanded its regulatory coverage with the addition of new rules limiting methane emissions from new or modified sites and equipment. In August 2020, the EPA also finalized a rule that rescinded the methane requirements in the 2016 NSPS for the production and processing segments of the oil and natural gas industry.

This final rule also made amendments to the fugitive emissions monitoring requirements in the 2016 NSPS for the oil and natural gas industry that included: changes to the frequency for monitoring fugitive emissions (also known as “leaks”) at well sites and compressor stations, requirements for pneumatic pumps at well sites, and reduced requirements for professional engineer certifications.

The Biden administration has pledged to review or reverse many Trump-era environmental policies, and it appears some or all of these recent changes to the 2016 NSPS for the oil and gas industry are in the spotlight of this initiative.

In addition, in March 2018, the EPA proposed to withdraw “control technique guidelines” the EPA had previously issued to assist states in developing reasonably achievable control technology requirements for sources of volatile organic compounds. The Obama administration had originally issued these guidelines as part of its strategy to reduce methane emissions.

In November 2018, the EPA revised a previously stayed rule defining site aggregation for air permitting purposes. Under this rule, it is possible that some sites could require additional permitting under the Clean Air Act, an outcome that could result in costs and delays to the Partnership’s operations. However, this rule revival is being challenged in court.

On November 18, 2016, the BLM published a final rule that was intended to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore Federal and Indian leases. Unlike the somewhat overlapping EPA regulations, which apply to new, modified and reconstructed sources, the BLM’s 2016 rule was drafted to address existing facilities, including a substantial number of existing wells that are likely to be marginal or low-producing, including leak detection and repair and other requirements regarding methane emissions. BLM issued a final rule in September 2018 that reduced certain compliance burdens deemed to be unnecessary, including requirements to write waste minimization plans, meet methane capture targets and use equipment that meets certain technical standards. BLM’s rule was challenged and struck down in federal court in 2020, although it is possible the Biden administration will reintroduce this type of regulation.

In March 2019, the EPA announced a voluntary disclosure program for new owners of upstream oil and natural gas exploration and facilities. The program was developed to encourage new owners of these facilities to participate because it provided regulatory certainty and clearly defined civil penalty mitigation beyond what was offered by the EPA’s existing self-disclosure policies. In December 2019, the EPA temporarily expanded its voluntary self-audit and disclosure program for upstream oil and natural gas facilities by giving existing owners the opportunity to find, correct, and self-disclose Clean Air Act violations.

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National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, 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. All proposed exploration and development plans on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

The Trump administration EPA issued regulations that significantly changed how a NEPA analysis is conducted. Key changes included eliminating cumulative impact analysis, revising the definition of effects, narrowing what actions are subject to NEPA review, and allowing project proponents a greater role in the environmental review of their own projects. The Biden administration has pledged to review many of these changes, which may result in their reversal.

Climate Change Legislation

More stringent laws and regulations relating to climate change and GHG emissions may be adopted in the future and could cause the Partnership to incur material expenses in complying with them. Both houses of Congress have considered legislation to reduce emissions of GHGs, but no legislation has yet passed. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.

The EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries including onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities.

The Biden administration has declared efforts to manage and control climate change a priority, evidenced by the immediate re-commitment of the United States to the Paris Agreement. It is possible this will result in additional federal initiatives to regulate greenhouse gas emissions. In January 2021, the Trump administration EPA issued a rule requiring the EPA to find that an individual industry, such as the power sector or oil and gas operators, collectively emits at least 3% of total U.S. greenhouse gases before setting emissions controls. Only the electric power sector would currently satisfy that requirement, according to the EPA’s own calculations. The Biden administration is likely to make an effort to reverse this rule.

Nonetheless, because of the lack of any comprehensive legislative program addressing GHGs, there is still a great deal of uncertainty as to how and whether federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally as well as some localities, also are considering or have implemented GHG regulatory programs or other steps to reduce GHG emissions. These potential regional, state and local initiatives may result in so-called cap and trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in the Partnership incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from its operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas the Partnership produces. The impact of such future programs cannot be predicted, but the Partnership does not expect its operations to be affected any differently than other similarly situated domestic competitors.

Endangered Species Act

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The Partnership’s operators may conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected properties that the Partnership owns. The designation of previously unprotected species as threatened or endangered in areas where the Partnership might conduct operations could result in limitations or prohibitions on its activities and could adversely impact the value of its leases.

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In August 2019, the Fish and Wildlife Service finalized revisions to ESA regulations that somewhat loosened procedures for listing species, recovery, reclassifications and critical habitat designations. The rules removed the requirement that listing, delisting or reclassification of species be made “without reference to possible economic or other impacts of such determination.” The rules also further relaxed the protection afforded to species listed as “threatened” from those that are endangered, with the protection for “threatened” species being made on more of a case-by-case basis. The Trump administration EPA also issued several Endangered Species Act decisions in the final days of 2020 that have been targeted by the Biden administration for review and possible reversal.

OSHA and Other Laws and Regulation

The Partnership is subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under Title III of CERCLA and similar state statutes require that the Partnership organize and/or disclose information about hazardous materials used or produced in the Partnership’s operations.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the Partnership’s cost of doing business and, consequently, affects the Partnership’s profitability, these burdens generally do not affect the Partnership any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. The drilling and production operations performed by the Partnership’s contracted operators are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which the Partnership operates also regulate one or more of the following:

● the location of wells;

● the method of drilling, completing and operating wells;

● the surface use and restoration of properties upon which wells are drilled;

● the plugging and abandoning of wells;

● the marketing, transportation and reporting of production;

● notice to surface owners and other third parties; and

● produced water and waste disposal.

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to the Partnership are also subject to the jurisdiction of various federal, state and local authorities, which can affect the Partnership’s operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

In addition, a number of states, such as North Dakota where the Partnership’s properties are located, and some tribal nations have enacted surface damage statutes, or SDAs. These laws are designed to compensate for damage caused by oil and natural gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and require specific payments by the operator to surface owners/users in connection with exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

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The Partnership will not control the availability of transportation and processing facilities that may be used in the marketing of its production. For example, the Partnership may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If the Partnership conducts operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by BLM, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

The Mineral Leasing Act of 1920, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. The Partnership qualifies as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non–reciprocal countries, there are presently no such designations in effect. It is possible that the holders of the Partnership’s common units may be citizens of foreign countries and do not own their common units in a U.S. corporation or even if such interest is held through a U.S. corporation, their country of citizenship may be determined to be non–reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by the Partnership could be subject to cancellation based on such determination.

Federal Regulation of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation

The availability, terms and cost of transportation service significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). The intrastate transportation, local distribution and retail sale of natural gas generally are subject to state regulation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act of 1978. FERC also authorizes the construction and operation of interstate natural gas pipelines under the Natural Gas Act (“NGA”).

Under FERC’s current regulatory regime, interstate natural gas transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Among other things, the FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

With respect to its review of applications for the construction and operation of interstate natural gas pipeline facilities under the NGA, FERC must comply with environmental review requirements of NEPA.

Wellhead natural gas sale prices are unregulated. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices. The Partnership cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the properties the Partnership owns.

Sales of the Partnership’s oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act (“ICA”). The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. In 2017, FERC issued a declaratory holding that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the (higher) filed tariff rate, would violate the ICA. Rehearing of this order is pending before FERC.

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Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to the Partnership’s costs of transporting gas to point-of-sale locations.

The pipelines used to gather and transport natural gas being produced by the Partnership are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet.

Transportation of the Partnership’s oil, natural gas liquids and purity components (ethane, propane, butane, iso–butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations, including Emergency Orders by the FRA. Revisions to PHMSA gathering line regulations and liquids pipelines regulations could result in the Partnership incurring significant expenses.

Exports of US Oil Production and Natural Gas Production

At the end of 2015, the U.S. Congress voted to end a decades-old prohibition of exports of oil produced in the lower 48 states of the U.S. Under the NGA, the U.S. Department of Energy (“DOE”) authorizes exports of U.S.-produced natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico and Canada. Under the NGA, FERC authorizes the construction and operation of natural gas pipeline facilities crossing the U.S. border used to export U.S.-produced natural gas. In addition, under the NGA, the DOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, while FERC authorizes the siting and construction of onshore and near-shore LNG export terminals. From 2012 through the end of 2020, DOE authorized large-scale, long-term exports of lower-48-U.S.-produced LNG and compressed natural gas totaling 46.94 billion cubic feet per day of natural gas to countries with which the U.S. has not entered into a free trade agreement providing for national treatment for trade in natural gas. In 2020, DOE issued a Final Policy Statement discontinuing its practice of granting a standard 20-year export term for long-term authorizations to export domestically produced natural gas from the lower-48 states to non-FTA countries, and adopting a term through December 31, 2050, as the standard export term for long-term non-FTA authorizations. Under DOE’s Policy Statement, holders of existing non-FTA authorizations may file an application with DOE requesting to amend its authorization to extend its export term through December 31, 2050.

Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. The Partnership does not believe that compliance with these laws will have a material adverse effect upon its operations.

Employees

The Partnership has no officers, directors or employees. Through the General Partner, the Partnership utilizes resources from Energy 11 and other third-parties to manage and administer the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner will be made by the Board of Directors of the General Partner and its officers.

General Corporate Information

Energy Resources 12, L.P. is a Delaware limited partnership founded in 2016 with principal offices at 120 W 3rd Street, Suite 220, Fort Worth, Texas 76102. The Partnership can be reached at (817) 882-9192 and the Partnership website address is www.energyresources12.com. The Partnership makes available, free of charge through its Internet website, its annual report on Form 10-K and quarterly reports on Form 10-Q, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after the Partnership electronically files such material with, or furnishes it to, the SEC. Information contained on the Partnership’s website is not incorporated by reference into this report.

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Item 1A.  Risk Factors

Risks Related to the Partnership’s Business, Results of Operations and Cash Flows

Crude oil prices declined significantly in the first quarter of 2020 and into the second quarter of 2020. If oil, natural gas or other hydrocarbon prices decrease and remain depressed for a prolonged period, cash flows from operations will decline and the Partnership may have to lower its distributions or may not be able to pay distributions at all.

The Partnership’s revenue, profitability and cash flow depend upon the prices for oil, natural gas and other hydrocarbons. The prices the Partnership receives for its production will be volatile and a drop in prices can significantly affect its financial results and adversely affect the Partnership’s ability to obtain credit, maintain its borrowing capacity and to repay indebtedness, all of which can affect the Partnership’s ability to pay distributions. Changes in prices have a significant impact on the value of the Partnership’s reserves and on its cash flows. Prices may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond the Partnership’s control, such as:

● the domestic and foreign supply of and demand for oil and natural gas and other hydrocarbons;

● regulations which may prevent or limit the export of oil, natural gas and other hydrocarbons;

● the amount of added production from development of unconventional natural gas reserves;

● the price and quantity of foreign imports of oil, natural gas and other hydrocarbons;

● the level of consumer product demand;

● adverse weather conditions, natural disasters and global health concerns, such as the COVID-19 coronavirus outbreak in early 2020;

● domestic and foreign governmental regulations, including environmental initiatives and taxation;

● overall domestic and global economic conditions;

● the value of the U.S. dollar relative to the currencies of other countries;

● 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, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

● the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

● the proximity and capacity of natural gas pipelines and other transportation facilities to the Partnership’s production;

● technological advances affecting energy consumption;

● price and availability of competitors’ supplies of oil and natural gas;

● speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

● the price and availability of alternative fuels; and

● the impact of energy conservation efforts.

Decreased oil, natural gas and other hydrocarbon prices will decrease Partnership revenues, and may also reduce the amount of oil, natural gas or other hydrocarbons that the Partnership can economically produce. If decreases occur, or if estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require the Partnership to write down, as a non–cash charge to earnings, the carrying value of its oil and natural gas properties for impairments. The Partnership is required to perform impairment tests on its assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. The Partnership may incur impairment charges in the future, which could have a material adverse effect on its results of operations in the period taken and the Partnership’s ability to borrow funds under a credit facility, which may adversely affect the Partnership’s ability to make cash distributions to holders of its common units and service its debt obligations.

The widespread outbreak of COVID-19 has significantly adversely impacted and disrupted, and is expected to continue to adversely impact and disrupt, the Partnership’s business and the industry in which the Partnership operates.

In December 2019, China reported an outbreak of COVID-19 in its Wuhan province. On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States declared a national emergency with respect to COVID-19. COVID-19 has spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures include significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy.

COVID-19’s impact to the global economy, in particular the oil and gas industry, has been unprecedented, as reduced demand for fossil fuels has resulted in a significant decline in commodity prices during March and April 2020. The Partnership experienced a decline in anticipated revenue during March 2020 and through 2020 due to commodity price declines. If demand for oil and gas as well as commodity prices remain low in 2021, the Partnership’s business will be negatively impacted. The Partnership cannot give any assurance as to when demand will return to more normal levels or if commodity prices will increase.

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The COVID-19 pandemic and related restrictions aimed at mitigating its spread have caused the General Partner to modify certain of the Partnership’s business practices, including limiting employee travel, encouraging work-from-home practices and other social distancing measures. Such measures may cause disruptions to the Partnership’s business and operational plans, which may include shortages of employees, contractors and subcontractors. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the disease, including the risk of infection of key employees, and the Partnership’s ability to perform certain functions could be impaired by these new business practices. For example, the Partnership’s reliance on technology has necessarily increased due to the General Partner’s encouragement of remote communications and other work-from-home practices, which could make the Partnership more vulnerable to cyber-attacks.

The spread of COVID-19 has caused severe disruptions in the global economy, specifically the oil and gas industry, and could potentially create widespread business continuity issues of an as yet unknown magnitude and duration.

COVID-19 has caused severe economic, market and other disruptions worldwide. In many respects, it is too early to quantify the long-term ramifications of COVID-19 on the global economy as well as oil and gas industry, the Partnership’s operators and the Partnership’s business. Further, it is currently not possible to predict how long the COVID-19 pandemic will last or the time that it will take for economic activity to return to prior levels. As a result, the Partnership cannot provide an estimate of the overall impact of COVID-19 on its business or when, or if, the Partnership and its operators will be able to resume normal, pre-COVID-19 operations. Nevertheless, sustained lower oil and gas prices and reduced demand resulting from COVID-19 present material uncertainty and risk with respect to the Partnership’s business, financial performance and condition, operating results and cash flows. In addition, low oil and natural gas prices may cause the Partnership’s undrilled wellsites to become uneconomic to develop.

As domestic demand for crude oil has declined substantially due to COVID-19, the General Partner cannot ensure that there will be a physical market for the Partnership’s production at economic prices until markets stabilize.

As a result of low commodity prices, the operators of the Partnership’s wells have and may curtail a portion of the Partnership’s estimated crude oil production and may store rather than sell additional crude oil production in the near future. Additionally, an excess supply of oil could lead to further curtailments by those operators. While the Partnership believes that the shutting-in of such production will not impact the productivity of such wells when reopened, there is no assurance the Partnership will not have a degradation in well performance upon returning those wells to production. The storing or shutting in of a portion of the Partnership’s production can also result in increased costs under midstream and other contracts. Any of the foregoing could result in an adverse impact on the Partnership’s revenues, financial position and cash flows.

The Partnership may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements and management fees to the General Partner, to enable the Partnership to make cash distributions to holders of its common units under its cash distribution policy.

The Partnership may not have sufficient available cash each month to enable it to make cash distributions to the holders of common units. The amount of cash the Partnership can distribute on its common units principally depends upon the amount of cash the Partnership generates from its operations, which will fluctuate from month to month based on, among other things:

● the amount of oil, natural gas and natural gas liquids the Partnership produces;

● the prices at which the Partnership sells its production;

● the Partnership’s ability to hedge commodity prices at economically attractive prices;

● the level of the Partnership’s capital expenditures, including its costs to participate in wells;

● the level of the Partnership’s operating and administrative costs including fees and reimbursement to the General Partner; and

● the level of the Partnership’s interest expense, which depends on the amount of its indebtedness and the interest payable thereon.

In addition, the actual amount of cash the Partnership will have available for distribution will depend on other factors, some of which are beyond the Partnership’s control, including:

● the amount of cash reserves established by the General Partner for the proper conduct of the Partnership’s business and for capital expenditures, which may be substantial;

● the operator(s) of the Partnership’s properties will control the timing of any capital expenditures necessary to drill or overhaul any wells on the properties the Partnership invests in;

● the cost of operations, infrastructure and drilling;

● the Partnership’s debt service requirements and other liabilities, if the Partnership increases debt levels;

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● fluctuations in the Partnership’s working capital needs;

● the Partnership’s ability to borrow funds;

● the timing and collectability of receivables; and

● prevailing economic conditions.

As a result of these factors, the amount of cash the Partnership distributes to holders of its common units may fluctuate significantly from month to month.

The Partnership has limited control over the activities on its properties.

Fourteen other companies operate the properties the Partnership has acquired. The Partnership has limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that it is required to fund. The failure of an operator of the Partnership’s wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in the Partnership’s best interest could reduce the Partnership’s production and revenues. The Partnership’s dependence on the operator and other working interest owners for these projects and its limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of the Partnership’s targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

The Partnership participates in oil and gas leases with third parties who may not be able to fulfill their commitments to the Partnership’s projects.

The Partnership owns less than 100% of the working interest in the Bakken Assets, and other parties own the remaining portion of the working interests. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. The Partnership could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Another working interest owner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of the Partnership’s co-owners do not pay their share of such costs, the Partnership would likely have to pay its share of those costs, and the Partnership may be unsuccessful in any efforts to recover these costs from its partners, which could materially adversely affect the Partnership’s financial position.

The Partnership’s results from operations may be impacted by a lack of geographical diversification.

All of the Partnership’s assets are located in concentrated areas of the Bakken shale in neighboring counties in North Dakota. While other companies and limited partnerships may have the ability to manage their risk by diversification, the narrow geographic focus of the Partnership’s business means that it may be impacted more acutely by factors affecting its industry or the region in which the Partnership operates than it would if its asset locations were more diversified. The Partnership may be disproportionately exposed to the effects of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of oil or natural gas. Additionally, the Partnership may be exposed to further risks, such as changes in field-wide rules and regulations that could cause the Partnership to permanently or temporarily shut-in all of its wells within the Williston Basin. The Partnership does not currently intend to broaden the geographic scope of its asset base.

The Partnership depends on oil and natural gas transportation and processing facilities and other assets that are owned by third parties.

The marketability of Partnership oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, physical damage, scheduled maintenance, legal or other reasons such as suspension of service due to legal challenges (see below regarding the Dakota Access Pipeline), could result in a substantial increase in costs, the shut-in of producing wells or the delay or discontinuance of development plans for the Bakken Assets. The negative effects arising from these and similar circumstances may last for an extended period of time.

The Dakota Access Pipeline (“DAPL”), a major pipeline running out of the Williston Basin, is subject to publicized ongoing litigation that could threaten its continued operation. In July 2020, a federal district court ordered DAPL to be shut down no later than August 6, 2020, pending the completion of an environmental impact statement that is expected to take at least a year to complete. The district court’s shut-down order was subsequently temporarily stayed by a federal circuit court of appeals, and DAPL currently remains operational. But a court-ordered shut-down remains possible, and there is no guarantee that DAPL will be permitted to resume or continue operations following the completion of the environmental review or any outstanding litigation.

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Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect the Partnership’s results of operations and financial condition.

The Partnership and the operators of its properties may encounter obstacles to marketing the Partnership’s share of oil, natural gas and other hydrocarbons, which could adversely impact the Partnership’s revenues.

The marketability of the Partnership’s production will depend upon numerous factors beyond the Partnership’s control, including the availability and capacity of natural gas gathering systems, pipelines and other transportation and processing facilities that the Partnership expects to be owned by third parties. Transportation space on the gathering systems and pipelines the Partnership expects to utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. The Partnership’s access to transportation and processing options and the marketing of the Partnership’s production can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, as well as the other risks discussed above. The availability of markets is beyond the Partnership’s control. If market factors dramatically change, the impact on the Partnership’s revenues could be substantial and could adversely affect the Partnership’s ability to produce and market oil, natural gas and natural gas liquids, the value of the Partnership’s common units and the Partnership’s ability to pay distributions on the Partnership’s common units and service any Partnership debt obligations.

The Partnership may be required to shut-in wells or delay initial production for lack of a viable market or because of the inadequacy or unavailability of pipeline, gathering system, processing, treating, fractionation or refining capacity. When that occurs, the Partnership will be unable to realize revenue from such wells until the inadequacy or unavailability is remedied. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

The Partnership will need additional funding in order to retain its full interest in the Bakken Assets.

The Partnership anticipates that it may be obligated to significantly invest within the next five years in drilling and well completion capital expenditures to fully participate in operator drilling programs in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements governing those properties. The Partnership will depend, at least in part, on increased cash flow from operations and may require additional financing to fund the anticipated capital expenditures needed to retain its full interest in the Bakken Assets. None of these funding sources is guaranteed, and if the Partnership is unable to obtain all of this funding, the Partnership may lose all or a portion of the assets acquired or reduce distributions, and its results of operations will be negatively affected accordingly.

Property interests that the Partnership has purchased or of which the Partnership participates in the development may not produce as projected and the Partnership may be unable to realize reserve potential, which could adversely affect the Partnership’s cash available for distribution.

The Partnership’s completed acquisitions and any decision to participate in the development of a property the Partnership owns required or will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors. Reserve estimates may be prepared by the operators or third parties for the operators of properties. The Partnership has engaged and may engage its own third-party petroleum engineers to review such reserve estimate reports and provide the Partnership with an independent assessment of the reserve estimates. The process of estimating oil and gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future oil and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds, all of which can be difficult to predict with accuracy. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact the Partnership’s financial conditions and results of operations and its ability to make cash distributions to holders of its common units and service its debt obligations.

Additional potential risks at the acquisition date and those related to development include, among other things:

● incorrect assumptions regarding the future prices of oil, natural gas and other hydrocarbons or the future operating or development costs of properties;

● incorrect estimates of the reserves and projected development results attributable to a property the Partnership owns;

● drilling, operating and other cost overruns by the operator of the properties;

● an inability to integrate successfully the properties the Partnership has acquired;

● the assumption of liabilities;

● the diversion of management’s attention from other business concerns; and

● losses of key employees.

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The Partnership could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in the Partnership’s area of operations. Higher costs could reduce the Partnership’s profitability and cash flow.

Historically, capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond the Partnership’s control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that the Partnership and its vendors will rely upon, and the cost of services and labor especially those required in horizontal drilling and completion. Historically, oil and natural gas prices have fluctuated resulting in fluctuating levels of drilling activity in the U.S. oil and natural gas industry. Lower prices typically lead to lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise faster than selling prices thereby negatively impacting the Partnership’s profitability, cash flow and causing it to possibly reconfigure or reduce its drilling program.

The Partnership’s hedging transactions will expose it to counterparty credit risk.

Periodically, the Partnership has engaged in hedging transactions to reduce, but not eliminate, the effect of volatility in oil, gas and other hydrocarbon prices. The Partnership’s hedging transactions expose the Partnership to risk of financial loss if a counterparty fails to perform under a derivative contract. The risk of counterparty non-performance is of particular concern when there are disruptions in the financial markets and there are significant declines in oil and natural gas prices. Either of these events could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. The Partnership is unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if the Partnership does accurately predict sudden changes, the Partnership’s ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of the Partnership’s hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that the Partnership would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities.

During periods of falling commodity prices the Partnership’s hedge receivable positions increase, which increases the Partnership’s exposure. If the creditworthiness of the Partnership’s counterparties deteriorates and results in their nonperformance, the Partnership could incur a significant loss.

The Partnership’s hedging activities could result in financial losses or could reduce the Partnership’s net income, which may adversely affect the Partnership’s ability to pay cash distributions to holders of its common units.

To achieve more predictable cash flows and to reduce the Partnership’s exposure to fluctuations in the prices of oil, natural gas and other hydrocarbons, the Partnership has and may enter into hedging arrangements for a significant portion of its estimated future production. If the Partnership experiences a sustained material interruption in its production, the Partnership might be forced to satisfy all or a portion of its hedging obligations without the benefit of the cash flows from the Partnership’s sale of the underlying physical commodity, resulting in a substantial diminution of its liquidity.

The Partnership’s ability to use hedging transactions to protect it from future price declines will be dependent upon oil and natural gas prices at the time the Partnership enters into future hedging transactions and the Partnership’s future levels of hedging, and as a result its future net cash flows may be more sensitive to commodity price changes. Additionally, it may not be possible or economic to hedge all of the hydrocarbons the Partnership produces because of the lack of a market for such hedges or other reasons. The Partnership may hedge certain hydrocarbons it produces by entering into swaps, collars or other contracts covering hydrocarbons the Partnership considers to be priced similarly to the hydrocarbons it produces and could be subject to losses if the prices for the hydrocarbons the Partnership produces do not match the hydrocarbons the Partnership contracts for.

The prices at which the Partnership hedges its production will be dependent upon commodity prices at the time the Partnership enters into these transactions, which may be substantially higher or lower than current oil, natural gas and other hydrocarbon prices. Accordingly, the Partnership’s hedges may not fully protect it from significant declines in oil and natural gas prices received for its future production. Conversely, the Partnership’s hedges may limit its ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of the Partnership’s future production will not be hedged as compared to previous years, which would result in its oil, natural gas and natural gas liquids revenues becoming more sensitive to commodity price changes. The General Partner will not be liable for any losses the Partnership incurs as a result of the Partnership’s hedge transactions.

The Partnership plans to rely on drilling to fully develop the properties the Partnership has acquired. If drilling and well completion are unsuccessful, the Partnership’s cash available for distributions and financial condition will be adversely affected.

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The Partnership has acquired oil and gas properties that are not fully developed and require that the Partnership engages in drilling and well completion to fully exploit the reserves attributable to the properties. Because the Partnership has acquired non-operated properties, it will not be in charge of the drilling and well completions but will be obligated to pay its pro rata share of drilling and completion costs or be subject to penalties. Drilling and completion of wells by its operators will involve numerous risks, including the risk that the Partnership will not encounter commercially productive oil or natural gas reservoirs. The Partnership may incur significant expenditures to drill and complete wells, including cost overruns. Additionally, current geoscience technology may not allow the Partnership to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that the Partnership will make substantial expenditures on drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to holders of the Partnership’s common units and for servicing any debt obligations.

The Partnership’s drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

● unexpected drilling or operating conditions;

● facility or equipment failure or accidents;

● shortages or delays in the availability of drilling rigs and equipment and in hiring qualified personnel;

● adverse weather conditions;

● shortages of water required for hydraulic fracturing or other operations;

● compliance with environmental and governmental requirements;

● reductions in oil or gas prices;

● proximity to and capacity of transportation and processing facilities;

● title problems;

● encountering abnormal pressures or unusual, unexpected or irregular geological formations;

● pipeline ruptures;

● fires, blowouts, craterings and explosions; and

● uncontrollable flows of oil or natural gas or well fluids.

Even if drilled, completed wells may not produce quantities of oil or natural gas that are economically viable or that meet earlier estimates of economically recoverable reserves. A productive well may become uneconomic if water or other deleterious substances are encountered, which impair or prevent the production of oil and/or natural gas from the well. Overall drilling success rates or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in the Partnership’s production and revenues and materially harm the Partnership’s operations and financial condition by reducing its available cash and resources.

The Partnership’s continued success depends upon its ability to develop oil and gas reserves that are economically recoverable.

In addition, the Partnership’s future oil and natural gas production will depend on its success in developing its assets to add to its reserves. If the Partnership is unable to replace reserves through drilling, the Partnership’s level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. The Partnership’s total proved reserves decline as reserves are produced unless the Partnership conducts other successful development activities. The Partnership’s ability to make the necessary capital investment to maintain or expand its asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. The Partnership may not be successful in developing its assets to increase its reserves.

The Partnership’s business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect the Partnership’s financial condition or results of operations and, as a result, the Partnership’s ability to pay distributions to holders of its common units and service any future debt obligations.

The Partnership’s business activities are subject to operational risks, including:

● damages to equipment caused by natural disasters such as earthquakes, adverse weather conditions, including tornadoes, hurricanes, drought and flooding;

● unexpected formations and pressures;

● facility or equipment malfunctions;

● pipeline ruptures or spills;

● fires, blowouts, craterings and explosions;

● release of toxic gasses;

● uncontrollable flows of oil or natural gas or well fluids; and

● surface fluid spills, saltwater contamination, and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.

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Any of these events could adversely affect the Partnership’s ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension cessation or of operations, and attorneys’ fees and other expenses incurred in the prosecution or defense of litigation and could also result in requirements to remediate, regulatory investigations, and/or the interruption of the Partnership’s business and/or the business of third parties.

As is customary in the industry, the operators of the properties maintain insurance against some but not all of these risks. The Partnership may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on the Partnership’s business activities, financial condition, results of operations and ability to pay distributions to holders of its common units and service any future debt obligations.

Risks Related to Investment in the Partnership

The Partnership depends on key personnel, the loss of any of whom could materially adversely affect future operations.

The Partnership’s success will depend to a large extent upon the efforts and abilities of Messrs. Knight and McKenney, the chief executive officer and chief financial officer. The loss of the services of one or more of these key employees could have a material adverse effect on the Partnership. The Partnership does not maintain key-man life insurance with respect to any employees. The Partnership’s business will also be dependent upon its ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause the Partnership to incur greater costs or prevent it from pursuing its acquisition and development strategy as quickly as the Partnership would otherwise wish to do.

The common units are not liquid and your ability to resell your common units will be limited by the absence of a public trading market and substantial transfer restrictions.

The common units generally will not be liquid because there is not a readily available market for the sale of common units, and one is not expected to develop. Further, although the Partnership Agreement contains provisions designed to permit the listing of common units on a national securities exchange, the Partnership does not currently intend to list the common units on any exchange or in the over-the-counter market.

Distributions to the Partnership’s common unitholders may not be sourced from its cash generated from operations but from indebtedness, and therefore the Partnership’s distributions during certain periods may exceed earnings and cash flows from operations, and this will decrease the Partnership’s distributions in the future; furthermore, the Partnership cannot guarantee that investors will receive any specific return on their investment.

The General Partner has the right to make distributions from the proceeds of borrowings and capital contributions. Offering proceeds that are returned to investors as part of distributions to them will not be available for investments in oil and gas properties. In addition, during certain periods, the Partnership expects that distributions may exceed the amount of earnings and cash flows from operations during such periods. The payment of distributions will decrease the cash available to invest in the Partnership’s oil and gas properties and will reduce the amount of distributions the Partnership may make in the future. The Partnership cannot and does not guarantee that investors will receive any specific return on their investment.

Despite terminating its existing credit facility in November 2019, the Partnership may enter into a new credit facility in the future, which would require the Partnership to use a portion of its cash flow to pay interest on and principal of any indebtedness when due, which will reduce the cash available to finance the Partnership’s operations and other business activities. This could limit the Partnership’s flexibility in planning for or reacting to changes in the Partnership’s business and the industry in which it operates.

If the General Partner elects to cause the Partnership to make distributions rather than reinvesting the cash flow in its business, the Partnership may be required to sell or farm-out properties or to elect not to participate in exploration or development drilling activities on its properties, which activities could turn out to be profitable.

If the Partnership were presented with an exploration or development drilling or other opportunity on its properties, and funding the opportunity would require the Partnership’s cash that is required in order to follow its distribution policy or for other purposes approved by the General Partner, the General Partner may elect to cause the Partnership to sell or farm-out the opportunity or decline to participate in the opportunity, even if the General Partner determines that the opportunity could have a favorable rate of return. The General Partner will have the right to cause the Partnership to participate in opportunities that will use the Partnership’s cash otherwise than in accordance with the distribution policy if the General Partner determines that pursuing such opportunity is in the best interests of the Partnership.

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The General Partner is subject to conflicts of interest in operating the Partnership, including conflicts of interest arising out of the General Partner’s ownership of the incentive distribution rights. The Partnership Agreement limits the General Partner’s fiduciary duties to the Partnership in connection with these conflicts of interest.

The General Partner is subject to conflicts of interest in operating the Partnership’s business. These conflicts include:

● conflicts caused by competition for the General Partner’s time and attention with other partnerships that the General Partner and its affiliates do and may sponsor and/or manage;

● conflicts caused by the incentive distribution rights which may cause the General Partner to conduct operations that are riskier to the Partnership, or to sell properties, in order to generate distributions from the incentive distribution rights; and

● conflicts caused by the management fee the Partnership pays to the General Partner since its compensation is a percentage of total gross equity proceeds raised in this offering.

The Partnership Agreement provides that the General Partner will have no liability to the Partnership or the holders of the common units for decisions made, if such decisions are made in good faith. In addition, the Partnership Agreement provides that if the General Partner receives a fairness opinion regarding the sale price of a property or in connection with a merger or the listing of the Partnership’s common units on a national securities exchange, including transactions that involve affiliates of the General Partner, the General Partner will be deemed to have acted in good faith.

The General Partner has sole responsibility for conducting the Partnership’s business and managing its operations. The General Partner and its affiliates will have conflicts of interest, which may permit them to favor their own interests to the detriment of holders of the Partnership’s common units.

Additional conflicts of interest may arise between the General Partner and its respective affiliates on the one hand, and the Partnership and the holders of its common units, on the other hand. In resolving these conflicts of interest, the General Partner may favor its own interests and the interests of its owners over the interests of holders of the Partnership’s common units. These conflicts include, among others, the following situations:

● neither the Partnership Agreement nor any other agreement requires affiliates of the General Partner to pursue a business strategy that favors the Partnership or to refer any business opportunity to the Partnership;

● the General Partner determines the amount and timing of its asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash that is distributed to holders of the Partnership’s common units or used to service its debt obligations;

● the General Partner controls the enforcement of obligations owed to the Partnership by the General Partner and its affiliates; and

● the General Partner decides whether to retain separate counsel, accountants or others to perform services for the Partnership.

Amounts paid to the General Partner, regardless of success of the Partnership’s activities, will reduce the cash the Partnership has available for distribution.

Subsequent to the Partnership’s first acquisition of the Bakken Assets on February 1, 2018, the General Partner and its affiliates began receiving an annual management fee, paid quarterly, which is 0.5% of total gross equity proceeds raised in the Partnership’s offering. After the completion of the Partnership’s best-efforts offering in October 2019, in which approximately $218 million in gross proceeds were raised, the annual management fee to the General Partner is approximately $1.1 million. In addition, the General Partner and its affiliates have been or will be reimbursed for third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and have been or will be reimbursed for general and administrative costs of the general partner allocable to the Partnership regardless of the Partnership’s success in acquiring, developing and operating properties. The fees and direct costs to be paid to the General Partner will reduce the amount of cash distributions to investors. With respect to third-party costs, the General Partner has sole discretion on behalf of the Partnership to select the provider of the services or goods and the provider’s compensation.

Because the General Partner has discretion to determine the amount and timing of any distribution the Partnership may make, there is no guarantee that cash distributions will be paid by the Partnership in any amount or frequency even if its operations generate revenues.

The timing and amount of distributions will be determined in the sole discretion of the General Partner. The level of distributions, when made, will primarily be dependent upon the Partnership’s levels of revenue, among other factors. Distributions may be reduced or deferred, in the discretion of the General Partner, to the extent that the Partnership’s revenues are used or reserved for any of the following:

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● compensation and fees paid to the General Partner and its affiliates as described above in “— Amounts paid to the General Partner, regardless of success of the Partnership’s activities, will reduce cash distributions;”

● repayment of borrowings;

● drilling and completing new wells;

● cost overruns on drilling, completion or operating activities;

● remedial work to improve a well’s producing capability;

● uninsured losses from operational risks including liability for environmental damages;

● direct costs and general and administrative expenses of the Partnership;

● reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

● indemnification of the General Partner and its affiliates by the Partnership for losses or liabilities incurred in connection with the Partnership’s activities.

Further, because the Partnership’s investments will be in depleting assets, unless reinvested, Partnership revenues and the amount available for distribution to partners will decline with the passage of time. Accordingly, there can be no assurance that the Partnership will be able to make regular distributions or that distributions will be made at any consistent rate or frequency.

The Partnership may be unable to sell its properties, merge with another entity or list the common units on a national securities exchange within its planned timeline or at all.

Beginning five to seven years after the termination of the Partnership’s offering, the Partnership plans either to sell its properties and distribute the proceeds of the sale, after payment of liabilities and expenses, to its partners; merge with another entity; or list the common units on a national securities exchange. The decision to sell the Partnership’s properties or merge with another entity will be based on a number of factors, including the domestic and foreign supply of and demand for oil, natural gas and other hydrocarbons, commodity prices, demand for oil and natural gas assets in general, the value of the Partnership’s assets, the projected amount of the Partnership’s oil and gas reserves, general economic conditions and other factors that are out of the Partnership’s control. In addition, the ability to list its common units on a national securities exchange will depend on a number of factors, including the amount of assets, revenues and earnings that the Partnership has at the time of listing, the then existing market for oil and gas master limited partnerships, the state of the U.S. securities markets, the Partnership’s ability to meet the requirements of national securities exchanges, securities laws and regulations and other factors. If the Partnership is unable to either sell its properties, merge or list the common units on a national securities exchange in accordance with its current plans, you may be unable to sell or otherwise transfer your common units and you may lose some or all of your investment. While the Partnership plans to seek a liquidity event within five to seven years, the Partnership Agreement does not obligate the General Partner to cause a liquidity event within that timeline. The timing of a liquidity event will be dependent upon many factors, including prevailing market conditions, and the Partnership Agreement gives the Partnership flexibility on timing so that the Partnership is not forced to act during periods of low oil and gas prices, or other disadvantageous situations.

The General Partner may cause the Partnership not to participate with the operator in the drilling of wells on the Partnership’s properties.

If the Partnership has the opportunity to participate in wells, the General Partner may decide to sell or farmout the well. Also, if a well is proposed under an operating agreement for one of the properties the Partnership owns, the General Partner may cause the Partnership to “non-consent” the well under the applicable operating agreement. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well. If the General Partner makes the decision to sell, farmout or non-consent a well or other development activity, the Partnership Agreement provides that the General Partner will have no liability to the Partnership so long as the decision is made in good faith.

Fees and cost reimbursements that must be paid to the General Partner and the Managing Dealer regardless of success of the Partnership’s activities will reduce the cash the Partnership has available for distribution.

The General Partner and its affiliates have and will receive reimbursement of third-party costs incurred in connection with the formation of the Partnership and the Partnership’s business activities and have and will be reimbursed for general and administrative costs of the General Partner allocable to the Partnership, regardless of the Partnership’s success in acquiring, developing and operating properties. In addition, effective February 1, 2018, the General Partner receives an annual management fee of approximately $1.1 million, paid quarterly, which is 0.5% of total gross equity proceeds raised in this offering. The Managing Dealer is eligible to receive the Dealer Manager Incentive Fees after Payout. The fees and direct costs to be paid to the General Partner and the Managing Dealer will reduce the amount of cash distributions to investors.

Risks Related to Laws, Regulations, Cybersecurity and Other External Factors

The Partnership is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting the Partnership’s operations.

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The Partnership’s business is subject to complex and stringent laws and regulations governing the acquisition, development, operation, production and marketing of oil and gas, taxation, safety matters and the discharge of materials into the environment. In order to conduct the Partnership’s operations in compliance with these laws and regulations, the operator(s) of the Partnership’s properties must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining and maintaining regulatory approvals or drilling permits could have a material adverse effect on the Partnership’s ability to develop its properties, and receipt of drilling permits with onerous conditions could increase the Partnership’s compliance costs. In addition, regulations or executive orders regarding resource conservation practices and the protection of correlative rights may affect the Partnership’s operations by limiting the quantity of oil, natural gas and natural gas liquids the Partnership may produce and sell.

The Partnership is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil, natural gas and natural gas liquids. While the cost of compliance with these laws is not expected to be material to the Partnership’s operations, the possibility exist that new laws, regulations, executive orders or enforcement policies could be more stringent and significantly increase the Partnership’s compliance costs. If the Partnership is not able to recover the resulting costs through insurance or increased revenues, the Partnership’s ability to pay distributions to holders of the Partnership’s common units and service the Partnership’s debt obligations could be adversely affected.

Federal and state legislative initiatives, including executive orders, relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and even could result in the Partnership ceasing business operations.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from dense rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The operators of the properties the Partnership owns will routinely use hydraulic fracturing techniques in most drilling and completion programs. In past legislative sessions, legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing using materials other than diesel under the Safe Drinking Water Act and to require disclosure of the chemicals used in the fracturing process; this legislation has not passed. At the state and local levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, public disclosure of fracturing chemicals or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities.

On January 27, 2021, the Biden administration signed an executive order directing the Secretary of the Interior to temporarily stop issuing new oil and gas leases on federal lands, allowing time to review and reset the federal government’s oil and gas leasing program. The Partnership’s existing leases and permits are operational and held by production, and therefore not impacted by this executive order. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Partnership owns producing properties, the Partnership could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from participating in drilling wells. More widespread or prolonged moratoriums or prohibitions of hydraulic fracturing could, depending on the makeup of the Partnership’s assets, cause the Partnership to cease business operations.

Additional regulatory scrutiny by the EPA could make it difficult to perform hydraulic fracturing, impact the Partnership’s ability to conduct business, and increase the Partnership’s costs of compliance and doing business.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. The EPA has announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. The EPA also issued a pretreatment standard for the discharge of wastewater resulting from hydraulic fracturing activities, prohibiting the discharges of wastewater pollutants from onshore unconventional oil and gas extraction to publicly owned treatment works. In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concluded that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited the EPA’s assessment. The historic trend of more expansive and stricter environmental regulation may continue for the long term. Any additional regulatory actions taken by the EPA could increase the costs of the Partnership’s operations or result in additional operating restrictions or delays. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that the Partnership ultimately is able to produce.

The Partnership’s financial condition and results of operations may be materially adversely affected if the Partnership incurs costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

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The Partnership may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of its wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

● the Clean Air Act, or the CAA, and comparable state laws and regulations that impose obligations related to emissions of air pollutants;

● the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated water;

● the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from oil and gas facilities;

● the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned by the Partnership or at locations to which the Partnership has sent waste for disposal;

● the Safe Drinking Water Act and state or local laws and regulations related to underground injection (including hydraulic fracturing);

● the Endangered Species Act and comparable state and local laws and regulations which protect endangered and threatened species and the ecosystems on which they depend;

● the National Environmental Policy Act and comparable state statutes which ensure that environmental issues are adequately addressed in decisions involving major governmental actions (including the leasing of government land);

● the Oil Pollution Act, or OPA, which subjects responsible parties to liability for removal costs and damages arising from an oil spill in waters of the U.S.; and

● emergency planning and community right to know regulations under the Title III of CERCLA and similar state statutes require that the Partnership organizes and/or discloses information about hazardous materials used or produced in the Partnership’s operations.

Under these laws and regulations, the Partnership could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties and the issuance of orders enjoining future operations. Certain environmental statutes, including CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

Climate change legislation or regulations restricting emissions of greenhouse gases, or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids the Partnership produces.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. These permitting provisions, to the extent applicable to the Partnership’s operations, could require the operator(s) of the Partnership’s properties to implement emission controls or other measures to reduce GHG emissions and the Partnership could incur additional costs to satisfy those requirements. Further, the EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources. Although some of these requirements have been rescinded under the Trump administration, the Biden administration has pledged to scrutinize these changes and possibly reverse them. The broader recent trend of more expansive and stricter climate change regulation may continue for the long term, including with the Biden administration’s return to the Paris Agreement global treaty to curb greenhouse gas emissions.

In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities the Partnership owns. Reporting of GHG emissions from such facilities is required on an annual basis. Should the operator(s) of the Partnership’s properties trigger the reporting requirement, the Partnership will incur costs associated with the reporting obligation.

In past legislative sessions, Congress considered legislation to reduce emissions of GHGs and many states and regions have adopted or have considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Federal efforts at a cap and trade program have not moved forward in Congress. Some members of Congress have publicly indicated an intention to introduce legislation to curb the EPA’s regulatory authority over GHGs. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, equipment and operations on the Partnership’s properties could require the Partnership to incur costs to reduce emissions of GHGs associated with the Partnership’s operations or could adversely affect demand for the oil, natural gas and natural gas liquids that the Partnership produces.

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Significant physical effects of climatic change have the potential to damage the Partnership’s facilities, disrupt the Partnership’s production activities and cause the Partnership to incur significant costs in preparing for or responding to those effects.

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, the operations that the Partnership plans to engage in may be adversely affected. Potential adverse effects could include damages to the Partnership’s facilities from powerful winds or rising waters in low lying areas, disruption of the Partnership’s production activities either because of climate-related damages to the Partnership’s facilities or the Partnership’s costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on the Partnership’s financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom the Partnership has a business relationship. The Partnership may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. Should drought conditions occur, the Partnership’s ability to obtain water in sufficient quality and quantity could be impacted and in turn, the Partnership’s ability to perform hydraulic fracturing operations could be restricted or made more costly. 

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact the Partnership’s operations.

The Partnership’s business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. The Partnership depends on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with the general partner and third-party partners. Unauthorized access to the Partnership’s seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in the Partnership’s exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport the Partnership’s production to market. A cyber-attack involving the Partnership’s information systems and related infrastructure, or that of the Partnership’s business associates, could negatively impact the Partnership’s operations in a variety of ways, including but not limited to, the following:

● Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on the Partnership’s ability to compete for oil and gas resources;

● Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

● Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;

● A cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt the Partnership’s major development projects;

● A cyber-attack on third party gathering, pipeline, or rail transportation systems could delay or prevent the Partnership from transporting and marketing its production, resulting in a loss of revenues;

● A cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing the Partnership from marketing its production or engaging in hedging activities, resulting in a loss of revenues;

● A cyber-attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for the Partnership’s production, lower natural gas prices, and reduced revenues;

● A cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

● A cyber-attack on the Partnership’s automated and surveillance systems could cause a loss in production and potential environmental hazards;

● A deliberate corruption of the Partnership’s financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and

● A cyber-attack resulting in the loss or disclosure of, or damage to, the Partnership’s or any of its customer’s or supplier’s data or confidential information could harm the Partnership’s business by damaging its reputation, subjecting it to potential financial or legal liability, and requiring it to incur significant costs, including costs to repair or restore its systems and data or to take other remedial steps.

All of the above could negatively impact the Partnership’s operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, the Partnership may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber-attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

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Loss of Partnership information and computer systems could adversely affect the Partnership’s business.

The Partnership will be heavily dependent on information systems and computer-based programs of its operators, including 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 the hardware or software network infrastructure, possible consequences include the Partnership’s loss of communication links, inability of the Partnership’s operators to find, produce, process and sell oil and natural gas and 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 the Partnership’s business.

Risks Related to the JOBS Act

The Partnership is an emerging growth company under the JOBS Act and it intends to take advantage of reduced disclosure and governance requirements applicable to emerging growth companies, which could result in the Partnership’s common units being less attractive to investors.

The Partnership is an emerging growth company, as defined in the JOBS Act, and it intends to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in the Partnership’s periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. The Partnership expects to continue to take advantage of these reporting exemptions until the Partnership is no longer an emerging growth company, which in certain circumstances could be for up to five years.

The JOBS Act will allow the Partnership to postpone the date by which it must comply with certain laws and regulations intended to protect investors and reduce the amount of information provided in reports filed with the SEC.

The JOBS Act is intended to reduce the regulatory burden on emerging growth companies. The Partnership meets the definition of an emerging growth company and so long as the Partnership qualifies as an emerging growth company, the Partnership may, among other things:

● be exempt from the provisions of Section 404(b) of the Sarbanes-Oxley Act requiring that the Partnership’s independent registered public accounting firm provide an attestation report on the effectiveness of its internal control over financial reporting;

● be exempt from the “say on pay” provisions (requiring a non-binding shareholder vote to approve compensation of certain executive officers) and the “say on golden parachute” provisions (requiring a non-binding shareholder vote to approve golden parachute arrangements for certain executive officers in connection with mergers and certain other business combinations) of the Dodd-Frank Act and certain disclosure requirements of the Dodd-Frank Act relating to compensation of the Partnership’s chief executive officer; and

● be permitted to omit the detailed compensation discussion and analysis from proxy statements and reports filed under the Securities Exchange Act of 1934 and instead provide a reduced level of disclosure concerning executive compensation.

The Partnership currently intends to take advantage of all of the reduced regulatory and reporting requirements that will be available to it so long as the Partnership qualifies as an emerging growth company.

Tax Risks to Common Unitholders

The Partnership’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes and not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service treats the Partnership as a corporation or the Partnership becomes subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to the Partnership’s common unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on the Partnership being treated as a partnership for U.S. federal income tax purposes. The Partnership has not requested, and does not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this or any other tax matter affecting it.

If the Partnership was treated as a corporation for U.S. federal income tax purposes, the Partnership would pay federal income tax on the Partnership’s taxable income at the corporate tax rate, which, effective January 1, 2018, is currently a maximum of 21% and likely would pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon the Partnership as a corporation, cash available for distribution to you would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to the unitholders, likely causing a substantial reduction in the value of the Partnership’s common units.

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Current law may change so as to cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Partnership to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states have ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such taxes on the Partnership will reduce the cash available for distribution to a unitholder.

You may be required to pay taxes on income from the Partnership even if you do not receive any cash distributions from the Partnership.

Because holders of the Partnership’s common units will be treated as partners to whom the Partnership will allocate taxable income which could be different in amount than the cash the Partnership distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the Partnership’s taxable income even if you receive no cash distributions from the Partnership. You may not receive cash distributions from the Partnership equal to your share of the Partnership’s taxable income or even equal to the tax liability that results from that income.

You may not qualify for percentage depletion deductions, and even if you do so qualify, you will be required to determine, and maintain records supporting, your deduction.

Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Internal Revenue Code (“Code”) Section 613A(c). For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. The Partnership cannot determine whether or provide any assurance that you will qualify as an independent producer. Further, if you do qualify as an independent producer, you are required to determine the amount of your allowed percentage depletion deduction and maintain records supporting such determination.

The Partnership cannot assure you that it will meet the requirements for you to deduct intangible drilling and development costs.

Federal tax law places substantial limits on taxpayers’ ability to deduct intangible drilling and development costs (“IDCs”). Generally speaking, an “operator” is permitted to elect to currently deduct or capitalize and deduct ratably over a 60-month period, costs that are properly characterized as IDCs that the operator incurs in connection with the drilling and development of oil and natural gas wells. For purposes of deducting IDCs, an “operator” is generally defined as one that owns a working or an operating interest in an oil or gas well. If the Partnership determines that it is an “operator” with respect to its oil and gas wells, the Partnership’s determination is not binding on the IRS. The IRS may assert that the Partnership is not an “operator” with respect to one or more of its oil or gas wells at the time that IDCs are incurred. If the IRS were successful in such a challenge, the Partnership and, therefore, you, would not be entitled to deduct the IDCs incurred in connection with such wells.

If the Partnership is eligible to deduct IDCs, the Partnership cannot assure you that IDCs will be deductible in any given year.

If the Partnership is deemed to be an operator with respect to one or more of its oil or gas wells, its classification of a cost as an IDC is not binding on the IRS. The IRS may reclassify an item classified by the Partnership as an IDC as a cost that must be capitalized or that is not deductible.

The IRS could challenge the timing of the Partnership’s deductions of IDCs, which could result in an increase your tax liabilities.

IDCs are generally deductible when the well to which the costs relate is drilled. In some cases, IDCs may be paid in one year for a well that is not drilled until the following year. In those cases, the prepaid IDCs will not be deductible until the year when the well is drilled unless (i) drilling on the well to which the prepayment relates starts within 90 days after the end of the year the prepayment is made or (ii) it is reasonable to expect that the well will be fully drilled within 3-1/2 months of the prepayment. All of the Partnership’s wells may not be drilled during the year when the Partnership pays IDCs pursuant to a drilling contract. As a result, the Partnership could fail to satisfy the requirements to deduct the IDCs in the year when paid and/or the IRS may challenge the timing of the Partnership’s deduction of prepaid IDCs.

The deduction for IDCs may not be available to you if you do not have passive income.

If you invest in the Partnership, your share of the Partnership’s deduction for IDCs in the year you invest will be a passive loss that can be used to offset only passive income. Such deductions cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Any unused passive loss from IDCs may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Certain taxpayers are not subject to the passive loss rules.

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On the disposition of property by the Partnership or of common units by you, certain deductions for IDCs, depletion, and depreciation must be recaptured as ordinary income.

You may be required to recapture as ordinary income certain deductions for IDCs, depletion, and depreciation on disposition of property by the Partnership or on disposition of the Partnership’s common units.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

The U.S. legislature regularly considers budget proposals that may impact many tax incentives and deductions that are currently used by U.S. oil and gas companies. Among others, budget provisions may include: repeal of the deduction of IDC; repeal of the percentage depletion deduction for oil and gas properties; repeal of the domestic manufacturing tax deduction for oil and gas companies; and an increase in the amortization period for geological and geophysical costs of independent producers.

The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could increase the amount of the Partnership’s taxable income allocable to you. The Partnership is unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any modifications to the federal income tax laws or interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in the Partnership’s common units.

Holders of common units may be subject to limit on the ability to deduct interest expense incurred by the Partnership.

In general, the Partnership is entitled to a deduction for interest paid or accrued on indebtedness properly allocable to the Partnership’s trade or business during its taxable year. However, for taxable years beginning after December 31, 2017, the Partnership’s deduction for “business interest” is limited to the sum of the Partnership’s business interest income and 30% of “adjusted taxable income.” For the purposes of this limitation, the Partnership’s adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

These rules were modified in 2020 by the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). Under the CARES Act, the Partnership may elect to increase the amount of business interest it is allowed to deduct by increasing the 30% limitation to 50% of adjusted taxable income for its 2019 and 2020 taxable years. Further, in determining the interest deductibility limitation for the Partnership’s 2020 taxable year, under the CARES Act, the Partnership may elect to utilize the amount of adjusted taxable income generated in its 2019 taxable year.

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Item 1B.  Unresolved Staff Comments

None

Item 2.  Properties

Information regarding the Partnership’s properties is contained in Item 1 – Business, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 8 – Financial Statements and Supplementary Data: Note 3. Oil and Gas Investments, appearing elsewhere within this Annual Report on Form 10-K.

Item 3.  Legal Proceedings

At the end of the period covered by this Annual Report on Form 10-K, the Partnership was not a party to any material, pending legal proceedings.

Item 4.  Mine Safety Disclosures

Not applicable.

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Part II

Item 5.  Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Common Units

As of December 31, 2020, there were approximately 11.0 million common units outstanding, which were held by approximately 3,600 limited partners. There is currently no established public trading market in which the Partnership’s common units are traded. Solely to assist trustees and custodians of individual retirement accounts (“IRAs”) containing an investment in the Partnership’s common units and to assist broker-dealers in meeting their customer account statement reporting obligations under Financial Industry Regulatory Authority (“FINRA”) rules for investments in the Partnership, the Partnership announced an estimated per common unit value of the Partnership’s common units as of December 31, 2020 of $16.76 per common unit, as further described below. There can be no assurance that this estimated value per common unit, or the method used to estimate such value, complies with requirements applicable to a trustee’s, custodian’s or broker-dealer’s obligations with respect to IRAs or FINRA’s reporting requirements.

The fair value estimate of the Partnership’s common units was based upon a third-party valuation, performed by Pinnacle Energy Services of Oklahoma City, Oklahoma, of the Partnership’s oil and natural gas properties and management’s estimate of the fair value of the Partnership’s other assets and liabilities as of December 31, 2020. The developed per common unit value range is $14.72 – $18.76. The Partnership utilized the mid-point of the assumptions discussed below to determine the estimated value per common unit above. The following is a summary of the details of the fair value estimate:

(in thousands, except per common unit data)	Estimate at 12/31/20
	(unaudited)
Estimated fair value of oil and gas properties	$	181,500
Estimated fair value of cash and cash equivalents		3,077
Estimated fair value of other assets and liabilities, net		309
Estimated fair value of preferred distribution rights		-
Estimated fair value of equity	$	184,886
Common units outstanding		11,032
Estimated value per common unit	$	16.76

Since the Partnership’s common units are not listed on a national securities exchange, no material public market exists for the Partnership’s common units. As a result, although not prepared for generally accepted accounting purposes, the value estimate of the Partnership’s oil and gas properties was derived from unobservable inputs and was based on the income approach as outlined in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures. In the income approach, the estimated value of the Partnership’s oil and gas properties was calculated from a discounted cash flow model using consolidated projected cash flows of the Partnership’s reserves, as well as a discount rate based on market conditions at December 31, 2020. An additional market-based adjustment was made to reflect the probability of successful future development of the Partnership’s oil and gas reserves at December 31, 2020. The Partnership’s cash and cash equivalents are all highly liquid with maturities of three months or less and the fair market value approximates the carrying value. The Partnership’s other assets and liabilities include receivables from the sale of oil, natural gas and natural gas liquids, accounts payable and accrued expenses, which are short-term in nature, and the carrying value of these assets and liabilities approximates fair value at December 31, 2020. The valuation methodology and calculations were reviewed by management of the Partnership and considered reasonable. The estimated value was not based on an appraisal of the Partnership’s assets.

As with any methodology used to estimate value, the methodology employed by the Partnership was based upon several estimates and assumptions that may not be accurate or complete and may not accurately reflect future conditions. The estimates and assumptions underlying the estimated value involve judgments with respect to, among other things, future economic, competitive, regulatory and financial market conditions and future business decisions which may not be realized and that are inherently subject to significant business, economic, competitive and regulatory uncertainties and contingencies, including, among others, risks and uncertainties described in the periodic reports filed by the Partnership with the Securities and Exchange Commission (“SEC”), all of which are difficult to predict and many of which are beyond the control of the Partnership. Further, different parties using different assumptions and estimates could derive a different estimated value per common unit, which could be significantly different from the Partnership’s estimated value per common unit.

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The estimated per common unit value does not represent: (i) the amount at which the Partnership’s common units would trade on a national securities exchange, (ii) the amount a limited partner would obtain if he or she tried to sell his or her common units or (iii) the amount limited partners would receive if the Partnership liquidated its assets and distributed the proceeds after paying all expenses and liabilities. Accordingly, with respect to the estimated value per common unit, the Partnership can give no assurance that:

• a limited partner would be able to resell his or her common units at this estimated value;

• a limited partner would ultimately realize distributions per common unit equal to the estimated value per common unit upon liquidation of the Partnership’s assets and settlement of its liabilities or a sale of the Partnership (in part because estimated values do not necessarily indicate the price at which individual assets or the Partnership could be sold, oil and gas property values fluctuate and change, and the estimated value may not take into account the expenses associated with such a sale);

• the Partnership’s common units would trade at a price equal to or greater than the estimated value per common unit if they were listed on a national securities exchange;

• the methodology used to estimate the value per common unit would be acceptable to FINRA or for compliance with requirements applicable to a trustee’s or custodian’s obligations with respect to IRAs; or

• any or all of the assumptions used in estimating the value per common unit will prove to be accurate or complete.

The estimated value reflects the fact that the estimate was calculated as of a point in time. The value of the Partnership’s common units will likely change over time and will be influenced by changes to the value of individual assets, changes in the oil and gas industry, as well as changes and developments in the energy and capital markets. The Partnership does not intend to update or otherwise revise the above information to reflect circumstances existing after the date when made or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the information are no longer appropriate.

As discussed above, the estimated value of the Partnership’s oil and gas properties was determined based on various market level assumptions, including but not limited to commodity market prices, discount rates and processing and transportation costs. Because the Partnership’s assets are operated by 14 third-party operators, some of the assumptions will vary by operator. The following is a list of key assumptions used in the calculation of the estimated value of the Partnership’s oil and gas properties, a component of the estimated value per common unit:

• NYMEX oil strip pricing as of January 1, 2021, which ranges from $48.26 per barrel to $44.95 per barrel as of January 1, 2021 to December 31, 2025, and an increase of 3% thereafter with price cap at $75.00 per barrel

• NYMEX gas strip pricing as of January 1, 2021, which ranges from $2.67 per Mcf to $2.50 per Mcf as of January 1, 2021 to December 31, 2025, and an increase of 3% thereafter with price cap of $4.50 per Mcf

• Differentials to NYMEX strip pricing due to product processing, transportation or contract terms

o Weighted average oil differential of $7.79 per barrel of oil

o Weighted average natural gas differential of $4.71 per Mcf of natural gas

o Natural gas liquids (NGL) pricing determined using weighted average of 6.7% of NYMEX oil price 

o Weighted average natural gas shrink of 28.2%

o Weighted average NGL yield of 124.98 barrels per MMcf of wet gas

• Discount rate – 10.0%

• Risk adjustments to calculated present value

o Proved developed producing (PDP) assets – 5.0%

o Proved developed non-producing (PDNP) assets – 10.0%

o Proved undeveloped (PUD) assets to be drilled within five years – 15.0%

o Proved undeveloped (PROB) assets to be drilled between five and ten years – 25.0%

o Proved undeveloped (POSS) assets to be drilled after ten years – 35.0%

o Proved developed and undeveloped non-consent assets – 50.0%

• Total lease operating and workover expenses per well estimated at $8.50 per barrel of oil

• Gross capital expenditures to drill and complete future development locations estimated between approximately $5.0 and $8.0 million per well, depending upon length of the well

A change in any of the assumptions would likely produce a different estimated value per common unit. For example:

• An increase in the discount rate assumption of 100 basis points would decrease the per common unit value range by approximately $1.64 per common unit, all other assumptions remaining the same;

• A decrease in the discount rate assumption of 100 basis points would increase the per common unit value range by approximately $1.94 per common unit, all other assumptions remaining the same;

• An increase in the average NYMEX oil and natural gas strip pricing assumptions of 500 basis points would increase the per common unit value range by approximately $2.00 per common unit, all other assumptions remaining the same;

• A decrease in the average NYMEX oil and natural gas strip pricing assumptions of 500 basis points would decrease the per common unit value range by approximately $2.04 per common unit, all other assumptions remaining the same;

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• An increase of 500 basis points in the risk adjustment percentage to calculated present value per reserve category would decrease the per common unit value range by approximately $0.98 per common unit, all other assumptions remaining the same; and

• A decrease of 500 basis points in the risk adjustment percentage to calculated present value per reserve category would increase the per common unit value range by approximately $0.98 per common unit, all other assumptions remaining the same.

Incentive Distribution Rights and Dealer Manager Incentive Fees

The General Partner received the Incentive Distribution Rights upon closing of the minimum offering in July 2017. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold in the Partnership’s best-efforts offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).

Distribution Policy

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

The Partnership Agreement provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

For the year ended December 31, 2020, the Partnership paid distributions of $1.396165 per common unit, or $15.4 million. For the year ended December 31, 2019, the Partnership paid distributions of $1.396164 per common unit, or $13.3 million.

Neither the Partnership nor the General Partner has adopted an equity compensation plan.

Item 6.  Selected Financial Data

Not applicable.

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with Item 8 – the Consolidated Financial Statements and Notes thereto, the introduction of Part I regarding “Forward-Looking Statements,” and Item 1A – Risk Factors appearing elsewhere in this Annual Report on Form 10-K.

Overview

Energy Resources 12, L.P. (the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on May 17, 2017, the date the Partnership’s initial Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission. The Partnership completed its best-efforts offering on October 24, 2019. Total common units sold were approximately 11.0 million for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

The general partner is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner are made by the Board of Directors of the General Partner and its officers. The Partnership has no officers, directors or employees.

The Partnership was formed to acquire primarily oil and gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”), for $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership closed on its second asset purchase (“Acquisition No. 2”), acquiring an additional non-operated working interest in the Bakken Assets for $82.5 million, subject to customary adjustments. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its best-efforts offering and available financing to close on the acquisitions.

As a result of these acquisitions and completed drilling during the period of ownership, as of December 31, 2020, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.8% non-operated working interest in 372 producing wells, an estimated approximate 1% non-operated working interest in 13 wells in various stages of the drilling and completion process and additional possible future development locations.

The Bakken Assets are operated by 14 third-party operators, including WPX Energy (NYSE: WPX), Marathon Oil (NYSE: MRO), EOG Resources (NYSE: EOG), Continental Resources (NYSE: CLR) and RimRock Oil and Gas.

COVID-19, Demand, Pricing and Production

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to be in the future. Global macroeconomic factors contributing to uncertainty within the industry include real or perceived geopolitical risks in oil-producing regions of the world, particularly the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by the Organization of the Petroleum Exporting Countries (“OPEC”); and the strength of the U.S. dollar in international currency markets.

In December 2019, China reported an outbreak of a novel coronavirus (“COVID-19”) in its Wuhan province. COVID-19 rapidly spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy. On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States declared a national emergency with respect to COVID-19.

Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020 and remained depressed through the remainder of 2020. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. These factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. NYMEX oil prices stabilized around $40 per barrel of oil in June 2020 and through the third quarter of 2020, and oil prices continued to increase through the fourth quarter of 2020, approaching $50 per barrel of oil in December 2020.

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The following table lists average NYMEX prices for oil and natural gas for the periods defined below:

	Year Ended December 31,		Year Ended December 31,		Percent
	2020		2019		Change
Average market closing prices (1)
Oil (per Bbl)	$	39.26	$	56.96		-31.1	%
Natural gas (per Mcf)	$	2.03	$	2.56		-20.7	%

(1) Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas)

In response to lower commodity prices and reduced demand caused by the factors described above, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs while also implementing other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. Certain operators of the Bakken Assets temporarily enacted some of these measures due to the inability to produce, process and sell oil and natural gas at economical prices; approximately 25% of the Partnership’s producing wells were shut in for at least a portion of the second quarter of 2020. While operators of the Bakken Assets have since returned significant inventory of existing wells to production, reduced sold production volumes and low commodity prices had a negative effect on the Partnership’s revenue and operating results during the second and third quarters of 2020.

The Partnership’s revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. The Partnership intends to seek opportunities to invest in its existing production wells via capital expenditures and/or drill new wells on existing leasehold sites when cash flow is available. However, the Partnership’s operating results will be negatively impacted if new investment in the Partnership’s undrilled acreage remains limited while operators of the Bakken Assets wait for commodity prices and market supply and demand imbalances to become more favorable.

As specified by the SEC, the prices for oil, natural gas and NGL used to calculate the Partnership’s reserves are based on the unweighted arithmetic average prices as of the first day of each of the twelve months during the year ended December 31, 2020. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2020 were $39.57 per barrel of oil and $1.99 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2020 were $31.82 per barrel of oil, $(2.33) per MMcf of natural gas and $3.13 per barrel of NGL. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2019 were $55.69 per barrel of oil and $2.58 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2019 were $49.42 per barrel of oil, $(1.61) per MMcf of natural gas and $2.74 per barrel of NGL.

Results of Operations for Years 2020 and 2019

In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly sold production in barrel of oil equivalent (“BOE”) units, (2) average sales price per unit for oil, natural gas and natural gas liquids, (3) production costs per BOE and (4) capital expenditures.

The following table is a summary of the results from operations, including production, of the Partnership’s non-operated working interest in the Bakken Assets for the years ended December 31, 2020 and 2019.

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	Year Ended December 31,
	2020		Percent of Revenue			2019		Percent of Revenue			Percent Change
Total revenues	$	34,914,718		100.0	%	$	64,430,817		100.0	%		-45.8	%
Production expenses		15,455,915		44.3	%		17,027,589		26.4	%		-9.2	%
Production taxes		2,924,746		8.4	%		5,772,463		9.0	%		-49.3	%
Depreciation, depletion, amortization and accretion		14,204,418		40.7	%		17,203,330		26.7	%		-17.4	%
General, administration and other expense		2,377,005		6.8	%		2,323,230		3.6	%		2.3	%
Sold production (BOE):
Oil		853,633					1,129,951					-24.5	%
Natural gas		154,081					141,508					8.9	%
Natural gas liquids		141,483					126,760					11.6	%
Total		1,149,197					1,398,219					-17.8	%
Average sales price per unit:
Oil (per Bbl)	$	37.37				$	54.11					-30.9	%
Natural gas (per Mcf)		1.87					2.36					-20.8	%
Natural gas liquids (per Bbl)		9.03					10.09					-10.5	%
Combined (per BOE)		30.38					46.08					-34.1	%
Average unit cost per BOE:
Production expenses		13.45					12.18					10.4	%
Production taxes		2.55					4.13					-38.4	%
Depreciation, depletion, amortization and accretion		12.36					12.30					0.5	%
Capital expenditures	$	8,822,410				$	32,179,357

Oil, natural gas and NGL revenues

For the years ended December 31, 2020 and 2019, revenues for oil, natural gas and NGL sales were $34.9 million and $64.4 million, respectively. Revenues for the sale of crude oil were $31.9 million and $61.1 million, respectively, which resulted in realized prices of $37.37 and $54.11 per barrel, respectively. Revenues for the sale of natural gas were $1.7 million and $2.0 million, respectively, which resulted in realized prices of $1.87 and $2.36 per Mcf, respectively. Revenues for the sale of NGLs were $1.3 million in both periods, which resulted in realized prices of $9.03 and $10.09 per BOE, respectively. Average realized prices in the fourth quarter of 2020 were approximately $40.19 per barrel of oil, $2.42 per Mcf of natural gas and $13.03 per BOE of NGL, compared to the fourth quarter of 2019 prices of approximately $52.12 per barrel of oil, $2.23 per Mcf of natural gas and $11.77 per BOE of NGL.

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Bakken. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. Due to oil supply produced in the Bakken exceeding demand and the storage capacity available at refineries, the Partnership’s oil price differentials increased during the second quarter of 2020. However, as market supply and demand imbalances began to stabilize in July 2020, the Partnership’s oil price differential returned closer to historical levels during the third and fourth quarters of 2020. In July 2020, a federal judge ruled that two significant pipelines that transport oil and natural gas from North Dakota fields must suspend operations due to environmental review and disputes over right to use land owned by Native Americans (the ruling was later stayed on appeal and the case remains active in court). If use of the region pipelines is suspended at a future date, the Partnership anticipates its differential would increase.

The Partnership’s results for the year ended December 31, 2020 were negatively impacted by the Partnership’s realized sales prices for oil, natural gas and NGLs, which decreased, in comparison to the year ended December 31, 2019, due to (i) a decline in market commodity prices (factors discussed in “COVID-19, Demand, Pricing and Production” above) and (ii) significant increases in the oil differential during the second quarter of 2020. In addition to lower realized sales prices, the Partnership’s sold oil production in 2020 was negatively impacted by cost-cutting measures implemented by operators of the Bakken Assets, as approximately 25% of the Partnership’s wells were shut in for at least a portion of the second quarter of 2020. The Partnership’s sold production decreased to approximately 1,300 BOE per day in May 2020. The Partnership’s sold production for the Bakken Assets was approximately 3,900 BOE per day for the fourth quarter of 2020 and approximately 3,100 BOE per day for the year ended December 31, 2020. The Partnership’s production volumes increased significantly in the fourth quarter of 2020 due to recently completed wells. In contrast, the Partnership’s sold production volumes for the year ended December 31, 2019 exceeded those for the year ended December 31, 2020, as fully operational existing wells and recently completed wells contributed to significant increases in the Partnership’s sold production volumes of oil, natural gas and NGL. The Partnership’s sold production for the Bakken Assets was approximately 4,700 BOE per day for the fourth quarter of 2019 and approximately 3,800 BOE per day for the year ended December 31, 2019.

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Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, then decline to more consistent levels.

Realized sales prices for natural gas and NGLs were also negatively impacted in 2020 due to processing and transportation constraints, discussed above in “COVID-19, Demand, Pricing and Production” and below in “Production Expenses”, as product leaves the region upon extraction and processing. Sold production volumes for natural gas and NGLs increased in 2020 compared to sold production volumes in 2019 due to the Partnership’s operators minimizing natural gas shrink throughout 2020.

If operators are unable to produce, process and sell oil and natural gas at economical prices, the operators of the Bakken Assets may curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production. Further, production is dependent on the investment in existing wells and the development of new wells. The Partnership has 13 wells currently in various stages of drilling and completion, and the timing of completion of these wells is unknown at this time. Therefore, the Partnership expects to experience natural production declines until market conditions improve, the 13 in-process wells are completed, and the operators of the Bakken Assets believe market conditions are favorable to proceed with new well drilling.

Operating costs and expenses

Production expenses

Production expenses are daily costs incurred by the Partnership to bring oil and natural gas out of the ground and to market, along with the daily costs incurred to maintain producing properties. Such costs include field personnel compensation, saltwater disposal, utilities, maintenance, repairs and servicing expenses related to the Partnership’s oil and natural gas properties, along with the gathering and processing contract in effect for the extraction, transportation and treatment of natural gas.

For the years ended December 31, 2020 and 2019, production expenses were $15.5 million and $17.0 million, and production expenses per BOE of sold production were $13.45 and $12.18, respectively. Production expenses per BOE increased in 2020 in comparison to 2019 primarily due to the following: (i) a decrease in sold production volumes along with fixed lease operating expenses; (ii) a portion of the Partnership’s wells had tubing erosion due to extreme sand production, which required significant rework to return these wells to production; and (iii) the costs to gather, process and market the Partnership’s production, specifically natural gas and NGLs, increased due to excess supply during the second and third quarters of 2020.

Production expenses for the fourth quarters of 2020 and 2019 were $4.4 million and $5.9 million, respectively, and production expenses per BOE of production were $12.17 and $13.58, respectively. Production expenses per BOE for the fourth quarter of 2020 were below production expenses per BOE of the same period of 2019 primarily due to a decrease in workover expenses, as significant workover expenses were incurred during the fourth quarter of 2019 to maintain well performance. In addition, the operating environment in the Willison Basin was altered due to the severe impacts of COVID-19, and the implementation of cost-saving measures by its operators allowed the Partnership to save on routine expenses to maintain producing wells, both for the full year and the fourth quarter of 2020. The Partnership anticipates its operators may be able to effectively gather, process and market its production at lower costs in 2021 based on fourth quarter of 2020 market supply and demand conditions.

Production taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGL to total sales. Production taxes for the years ended December 31, 2020 and 2019 were $2.9 million (8% of revenue) and $5.8 million (9% of revenue), respectively. Production taxes for the fourth quarters of 2020 and 2019 were $1.0 million (8% of revenue) and $1.6 million (9% of revenue), respectively. Sold oil production accounted for approximately 74% of total sold production in 2020, compared to approximately 81% in 2019.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal, advisory, consulting and management fees. General and administrative costs for the years ended December 31, 2020 and 2019 were $2.4 million and $2.3 million, respectively.

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Depreciation, depletion, amortization and accretion (“DD&A”)

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. The Partnership’s DD&A for the years ended December 31, 2020 and 2019 was $14.2 and $17.2 million, respectively, and DD&A per BOE of production was $12.36 and $12.30, respectively. DD&A for the fourth quarters of 2020 and 2019 was $4.0 million and $5.9 million, respectively, and DD&A per BOE of production was $11.12 and $13.63, respectively.

The decrease in DD&A expense per BOE of production for the fourth quarter of 2020, compared to the fourth quarter of 2019, is primarily due to the Partnership’s significant investment in new wells during the fourth quarter of 2019.

Interest income (expense), net

Interest income, net for the year ended December 31, 2020 was $30,000, and Interest expense, net for the year ended December 31, 2019 was $1.6 million, respectively. The primary component of Interest expense, net, during 2019 was interest expense on the Partnership’s credit facility that was terminated in November 2019.

Loss on extinguishment of debt

In November 2019, upon the termination of its revolving credit facility, the Partnership recognized a loss on extinguishment of approximately $1.0 million related to its remaining unamortized deferred loan costs associated with the origination of its credit facility and was recorded as Loss on extinguishment of debt.

Gain (loss) on derivatives, net

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.

The Partnership did not designate its 2019 or 2020 derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gain (loss) recorded during the periods presented.

	Year Ended December 31, 2020			Year Ended December 31, 2019
Settlements on matured derivatives, net	$	1,116,113		$	(56,348	)
Loss on mark-to-market of derivatives, net		(387,305	)		(1,086,944	)
Gain (loss) on derivatives, net	$	728,808		$	(1,143,292	)

The mark-to-market net losses recorded for the years ended December 31, 2020 and 2019 represent the change in fair value of the Partnership’s derivative instruments held at period-end. These unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.

The Partnership’s oil production contracts that expired during the year ended December 31, 2020 represented approximately 168,000 barrels of oil. The Partnership’s realized net gain of approximately $1.1 million equated to an approximate gain of $6.66 per barrel of oil. The Partnership’s oil production contracts that expired during the fourth quarter of 2020 represented approximately 61,000 barrels of oil. The Partnership’s realized loss of approximately $49,000 equated to an approximate loss of $0.81 per barrel of oil.

The Partnership’s oil production contracts that expired during the year ended December 31, 2019 represented approximately 326,000 barrels of oil and 230,000 Mcf of natural gas. The Partnership’s realized net loss of approximately $56,000 equated to an approximate loss of $0.24 per barrel of oil and an offsetting approximate gain of $0.10 per Mcf of natural gas. The Partnership’s oil production contracts that expired during the fourth quarter of 2019 represented approximately 117,000 barrels of oil and 120,000 Mcf of natural gas. The Partnership’s realized gain of approximately $23,000 equated to an approximate gain of $0.11 per barrel of oil and an approximate gain of $0.09 per Mcf of natural gas.

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The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil production as of December 31, 2020.

	Costless Collar Volumes (Bbl)		Floor / Ceiling Prices ($)
01/2021 - 05/2021		68,247	38.00 / 44.85
01/2021 - 05/2021		68,247	37.50 / 46.00

Supplemental Non-GAAP Measure

The Partnership uses “Adjusted EBITDAX”, defined as earnings before (i) interest income (expense), net; (ii) income taxes; (iii) depreciation, depletion, amortization and accretion; (iv) exploration expenses; (v) (gain)/loss on the mark-to-market of derivative instruments; and (vi) loss on extinguishment of debt, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as alternatives to, net income (loss), operating income, cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. Adjusted EBITDAX is not necessarily indicative of funds available to fund the Company’s cash needs, including its ability to make cash distributions. Although Adjusted EBITDAX, as calculated by the Partnership, may not be comparable to Adjusted EBITDAX as reported by other companies that do not define such terms exactly as the Partnership defines such terms, the Partnership believes this supplemental measure is useful to investors when comparing the Partnership’s results between periods and with other energy companies.

The Partnership believes that the presentation of Adjusted EBITDAX is important to provide investors with additional information (i) to provide an important supplemental indicator of the operational performance of the Partnership’s business without regard to financing methods and capital structure, and (ii) to measure the operational performance of the Partnership’s operators.

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the years ended December 31, 2020 and 2019.

	Year Ended December 31, 2020			Year Ended December 31, 2019
Net income	$	711,301		$	18,340,788
Interest (income) expense, net		(29,859	)		1,620,953
Depreciation, depletion, amortization and accretion		14,204,418			17,203,330
Exploration expenses		-			-
Non-cash loss on mark-to-market of derivatives		387,305			1,086,944
Loss on extinguishment of debt		-			999,172
Adjusted EBITDAX	$	15,273,165		$	39,251,187

Liquidity and Capital Resources

With the completion of the Partnership’s best-efforts offering in October 2019 and extinguishment of the Partnership’s revolving credit facility in November 2019, the Partnership’s principal sources of liquidity are cash on-hand and the cash flow generated from the properties the Partnership owns. The Partnership anticipates that cash on-hand and cash flow from operations will be adequate to meet its liquidity requirements for at least the next 12 months, including completing capital expenditures discussed below. Although the Partnership anticipates its cash on-hand and cash flow from operations to be adequate to fund its cash requirements, another steep decline in market prices for oil and natural gas, such as the instance observed during the second quarter of 2020 due to COVID-19, and/or production not replenished through the completion of new well investments could have a significant impact on the Partnership’s cash flow from operations and available cash on-hand. These factors could also impact the Partnership’s ability to fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets. Although the Partnership did extinguish its revolving credit facility in November 2019, the Partnership may utilize available financing for future capital expenditures.

Financing

On August 31, 2018, the Partnership entered into a loan agreement (“Loan Agreement”) with Simmons Bank, as administrative agent and the lenders party thereto, which provided for a revolving credit facility (“Credit Facility”) with an initial commitment amount of $60 million. The Credit Facility proceeds of $60.0 million borrowed at closing were used to fund the purchase of Acquisition No. 2, as described above. On November 26, 2019, the Partnership elected to terminate the Loan Agreement, which extinguished the Credit Facility and terminated the related mortgage secured by the Partnership’s non-operating working interests in the Bakken Assets. At the date of termination, the Partnership had no outstanding borrowings on the Loan Agreement. Early termination of the Loan Agreement did not require payment of any early termination penalties.

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Partners’ Equity

The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

Under the agreement with the Managing Dealer, the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).

Distributions

Prior to “Payout,” which is defined below, all distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

The Partnership Agreement provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

For the year ended December 31, 2020, the Partnership paid distributions of $1.396165 per common unit, or $15.4 million. For the year ended December 31, 2019, the Partnership paid distributions of $1.396164 per common unit, or $13.3 million. The Partnership generated $16.3 million and $36.1 million in cash flow from operations for the years ended December 31, 2020 and 2019, respectively.

While the Partnership’s goal is to maintain a relatively stable distribution rate over the life of its program, the General Partner monitors monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations and capital expenditures for new wells. In light of the global economic volatility and a low commodity price environment in 2020, as discussed in the “COVID-19, Demand, Pricing and Production” section above, there can be no assurance as to the classification or duration of distributions at the current distribution rate of $1.40 per common unit per year. If distributions are not paid or are reduced, the difference to the current distribution rate of $1.40 per common unit will be deferred and is required to be paid before final Payout occurs, as discussed above.

Oil and Gas Properties

Future Investment

The Partnership incurred approximately $8.8 million and $32.2 million, respectively, in capital expenditures for the years ended December 31, 2020 and 2019. The Partnership expects to invest approximately $8 to $10 million in capital expenditures during 2021, including approximately $0.4 million in capital expenditures to complete the 13 wells in process at December 31, 2020. In addition to the estimated capital expenditures in 2021, the Partnership anticipates that it may be obligated to invest an additional $60 to $70 million in drilling capital expenditures from 2022 through 2025 to participate in new well development in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets.

44

Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for 2021. Current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash on hand and cash generated by operating activities. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well and would be subject to a non-consent penalty.

Oil, Natural Gas and NGL Reserves

The Partnership updated its proved undeveloped reserves (“PUD”) during the second quarter of 2020 as a result of lower oil and natural gas prices as well as changes in the planned timing of drilling and completing PUD reserve locations outside of the SEC five-year window. See Note 9. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) in Part II, Item 8 – Financial Statements and Supplementary Data for complete information on the Partnership’s reserves as of December 31, 2020.

Transactions with Related Parties

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to existing related party transactions, as well as any new significant related party transactions.

See further discussion in Note 8. Related Parties in Part II, Item 8 – Financial Statements and Supplementary Data and in Part III, Item 13 — Certain Relationships and Related Transactions, and Director Independence, appearing elsewhere in this Annual Report on Form 10-K.

Critical Accounting Policies and Estimates

The discussion and analysis of the Partnership’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires the Partnership to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of the Partnership’s accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. The Partnership bases these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as the Partnership’s operating environment changes and as new events occur.

The Partnership’s critical accounting policies are important to the portrayal of both its financial condition and results of operations and require the Partnership to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. The Partnership would report different amounts in its consolidated financial statements, which could be material, if the Partnership used different assumptions or estimates. The Partnership believes that the following are the critical accounting policies used in the preparation of its consolidated financial statements.

Oil and Natural Gas Properties

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

45

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Partnership is entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

The Partnership’s estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids 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 renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, the Partnership must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Partnership’s reserves. Independent reserve engineers prepare the Partnership’s reserve estimates at the end of each year.

Despite the inherent imprecision in these engineering estimates, the Partnership’s reserves are used throughout the Partnership’s financial statements. For example, since the Partnership uses the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact its depreciation, depletion and amortization expense. The Partnership’s reserves are also the basis of the Partnership’s supplemental oil and natural gas disclosures.

46

Accounting for Asset Retirement Obligations

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The Partnership’s removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable and other current assets in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership 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. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Recent Accounting Standards

See Note 2. Summary of Significant Accounting Policies in Part II, Item 8 – Financial Statements and Supplementary Data for a summary of recent accounting standards.

Subsequent Events

In January 2021, the Partnership declared and paid $1.5 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.

In February 2021, the Partnership declared and paid $1.2 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Item 7A. Quantitative and Qualitative Disclosure about Market Risk

Information regarding the Partnership’s hedging programs to mitigate commodity risks is contained in Item 1 – Business, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 8 – Financial Statements and Supplementary Data: Note 6. Risk Management, appearing elsewhere within this Annual Report on Form 10-K.

47

Item 8.  Financial Statements and Supplementary Data

Financial Statements

Report of Independent Registered Public Accounting Firm

To the Shareholders and the General Partner of Energy Resources 12, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Energy Resources 12, L.P. (the “Partnership”) as of December 31, 2020 and 2019, the related consolidated statements of operations, Partners’ equity, and cash flows for each of the two years in the period ended December 31, 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s 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 Partnership 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2017.

Richmond, Virginia

March 17, 2021

48

Energy Resources 12, L.P.

Consolidated Balance Sheets

	December 31,			December 31,
	2020			2019
Assets
Cash and cash equivalents	$	3,076,840		$	14,834,452
Accounts receivable and other current assets		5,629,026			8,186,604
Total Current Assets		8,705,866			23,021,056
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $36,136,401 and $21,955,397, respectively		192,170,057			197,498,771
Total Assets	$	200,875,923		$	220,519,827
Liabilities
Accounts payable and accrued expenses	$	3,658,846		$	9,052,746
Derivative liability		594,632			207,327
Total Current Liabilities		4,253,478			9,260,073
Asset retirement obligations		624,089			570,795
Total Liabilities		4,877,567			9,830,868
Partners’ Equity
Limited partners' interest (11,031,579 common units issued and outstanding, respectively)		195,998,571			210,689,174
General partner's interest		(215	)		(215	)
Total Partners’ Equity		195,998,356			210,688,959
Total Liabilities and Partners’ Equity	$	200,875,923		$	220,519,827

See notes to consolidated financial statements.

49

Energy Resources 12, L.P.

Consolidated Statements of Operations

	Year Ended			Year Ended
	December 31, 2020			December 31, 2019
Revenues
Oil	$	31,904,428		$	61,146,651
Natural gas		1,732,123			2,005,423
Natural gas liquids		1,278,167			1,278,743
Total revenue		34,914,718			64,430,817
Operating costs and expenses
Production expenses		15,455,915			17,027,589
Production taxes		2,924,746			5,772,463
General and administrative expenses		2,377,005			2,323,230
Depreciation, depletion, amortization and accretion		14,204,418			17,203,330
Total operating costs and expenses		34,962,084			42,326,612
Operating income (loss)		(47,366	)		22,104,205
Interest income (expense), net		29,859			(1,620,953	)
Loss on extinguishment of debt		-			(999,172	)
Gain (loss) on derivatives, net		728,808			(1,143,292	)
Total other expense, net		758,667			(3,763,417	)
Net income	$	711,301		$	18,340,788
Basic and diluted net income per common unit	$	0.06		$	1.92
Weighted average common units outstanding - basic and diluted		11,031,579			9,555,311

See notes to consolidated financial statements.

50

Energy Resources 12, L.P.

Consolidated Statements of Partners’ Equity

	Limited Partner					General Partner			Total Partners'
	Common Units		Amount			Amount			Equity
Balances - December 31, 2018		7,857,359		146,001,359			(215	)		146,001,144
Net proceeds from issuance of common units		3,174,220		59,633,446			-			59,633,446
Distributions declared and paid to common units ($1.396164 per common unit)		-		(13,286,419	)		-			(13,286,419	)
Net income		-		18,340,788			-			18,340,788
Balances - December 31, 2019		11,031,579	$	210,689,174		$	(215	)	$	210,688,959
Distributions declared and paid to common units ($1.396165 per common unit)		-		(15,401,904	)		-			(15,401,904	)
Net income		-		711,301			-			711,301
Balances - December 31, 2020		11,031,579	$	195,998,571		$	(215	)	$	195,998,356

See notes to consolidated financial statements.

51

Energy Resources 12, L.P.

Consolidated Statements of Cash Flows

	Year Ended			Year Ended
	December 31, 2020			December 31, 2019
Cash flow from operating activities:
Net income	$	711,301		$	18,340,788
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		14,204,418			17,203,330
Loss on mark-to-market of derivatives		387,305			1,086,944
Loss on extinguishment of debt		-			999,172
Non-cash expenses, net		-			513,770
Changes in operating assets and liabilities:
Accounts receivable and other current assets		2,557,578			(4,755,540	)
Accounts payable and accrued expenses		(1,540,250	)		2,697,734
Net cash flow provided by operating activities		16,320,352			36,086,198
Cash flow from investing activities:
Cash paid for acquisition of oil and natural gas properties		(110,073	)		(1,367,256	)
Additions to oil and natural gas properties		(12,565,987	)		(36,408,112	)
Net cash flow used in investing activities		(12,676,060	)		(37,775,368	)
Cash flow from financing activities:
Net proceeds from (payments on) revolving credit facility		-			(39,500,000	)
Net proceeds related to issuance of common units		-			59,627,639
Distributions paid to limited partners		(15,401,904	)		(13,286,419	)
Net cash flow provided by (used in) financing activities		(15,401,904	)		6,841,220
Increase (decrease) in cash and cash equivalents		(11,757,612	)		5,152,050
Cash and cash equivalents, beginning of period		14,834,452			9,682,402
Cash and cash equivalents, end of period	$	3,076,840		$	14,834,452
Interest paid	$	-		$	1,170,811
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	2,095,846		$	6,048,081

See notes to consolidated financial statements.

52

Energy Resources 12, L.P.

Notes to Consolidated Financial Statements

December 31, 2020

Note 1.  Partnership Organization

Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. The proceeds from the sale of the common units have been used to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties.

As of December 31, 2020, the Partnership owned an approximate 5.8% non-operated working interest in 372 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Partnership also owns an estimated approximate 1% non-operated working interest in 13 wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners.

The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership.

The Partnership’s fiscal year ends on December 31. 

Note 2.  Summary of Significant Accounting Policies

Basis of Presentation

The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).

Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

Property and Depreciation, Depletion and Amortization

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

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Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Partnership’s accounts receivable are due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2020 and 2019, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible and the Partnership’s operators do not have a history of non-payment. For the years ended December 31, 2020 and 2019, the Partnership’s oil, natural gas and NGL sales were through 14 operators and approximately 92% and 91% of the Partnership’s total revenue was generated through sales by four operators, respectively. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

Accounting for Asset Retirement Obligations

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

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The following table shows the activity for the years ended December 31, 2020 and 2019 relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2018	$	383,255
Well additions		49,801
Accretion		20,607
Revisions (1)		117,132
Balance as of December 31, 2019		570,795
Well additions		29,880
Accretion		23,414
Revisions		-
Balance as of December 31, 2020	$	624,089

(1) During 2019, six wells owned by the Partnership were deemed to be shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells.

Environmental Costs

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2020 and 2019, there were no such costs accrued.

Use of Estimates

The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

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Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable and other current assets in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership 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. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. 

Reclassifications

Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Net Income per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 7) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

Note 3.  Oil and Gas Investments

On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $90.5 million, including all closing costs and assumed liabilities. On August 31, 2018, the Partnership completed its second purchase of an additional non-operated working interest in the Bakken Assets for approximately $81.3 million, including all closing costs and assumed liabilities. As of December 31, 2020, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.8% non-operated working interest in 372 producing wells, and an estimated approximate 1% non-operated working interest in 13 wells in various stages of the drilling and completion process.

From September 1, 2017, the effective date of Acquisition No. 1, to December 31, 2020, the Partnership has participated in the drilling of 180 wells, of which 167 have been completed and 13 wells are in various stages of completion at December 31, 2020. The Partnership incurred approximately $8.8 million and $32.2 million in capital drilling and completion costs for the years ended December 31, 2020 and 2019, respectively. The Partnership anticipates approximately $0.4 million of capital expenditures to be incurred in first half of 2021 to complete the 13 wells in various stages of completion at December 31, 2020; however, actual capital expenditures incurred may exceed this range.

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Evaluation for Potential Impairment of Oil and Natural Gas Investments

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Bakken Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of January 1, 2021, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Bakken Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of December 31, 2020.

If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.

Non-consent wells

Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute.

Through its 2018 acquisitions, the Partnership acquired 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.

Note 4. Debt

On August 31, 2018, the Partnership entered into a loan agreement (“Loan Agreement”) with Simmons Bank, as administrative agent and the lenders party thereto, which provided for a revolving credit facility (“Credit Facility”) with an initial commitment amount of $60 million. The Credit Facility proceeds of $60.0 million borrowed at closing were used to fund the purchase of Acquisition No. 2, as described above, and pay closing costs. On November 26, 2019, the Partnership elected to terminate the Loan Agreement, which extinguished the Credit Facility and terminated the related mortgage secured by the Partnership’s non-operating working interests in the Bakken Assets. At the date of termination, the Partnership had no outstanding borrowings on the Loan Agreement. Early termination of the Loan Agreement did not require payment of any early termination penalties.

In conjunction with Acquisition No. 2 and the closing on the Loan Agreement, the Partnership capitalized $1.7 million of deferred loan costs, and the Partnership was amortizing these loan costs over the life of the Credit Facility to its maturity date of August 31, 2021. In November 2019, upon the termination of the Credit Facility, the Partnership expensed the remaining unamortized deferred loan costs and recorded a Loss on extinguishment of debt of $1.0 million on the Partnership’s consolidated statement of operations.

Note 5. Fair Value of Financial Instruments

The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:

● Level 1: Quoted prices in active markets for identical assets

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● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

● Level 3: Significant unobservable inputs

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the years ended December 31, 2020 and 2019, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019.

	Year Ended December 31, 2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(594,632	)	$	-
Total	$	-	$	(594,632	)	$	-

	Year Ended December 31, 2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(207,327	)	$	-
Total	$	-	$	(207,327	)	$	-

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheets as Derivative liability at December 31, 2020 and 2019. See additional detail in Note 6. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s cash and cash equivalents, accounts receivable and other current assets, accounts payable and accrued expenses reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

Note 6. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and the Partnership’s future earnings are subject to these risks. Therefore, the Partnership periodically enters into derivative contracts to manage the commodity price risk on a portion of the Partnership’s anticipated future oil and gas production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.

As of December 31, 2020 and 2019, the Partnership’s derivative instruments were in a loss position; therefore, current liabilities of approximately $0.6 million and $0.2 million, respectively, which approximate fair value, were recognized in Derivative Liability on the Partnership’s consolidated balance sheets.

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The Partnership determined the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 5. Fair Value of Financial Instruments.

The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect a realized net gain on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) losses below represent the change in fair value of derivative instruments which were held at period-end.

	Year Ended December 31, 2020			Year Ended December 31, 2019
Settlements on matured derivatives, net	$	1,116,113		$	(56,348	)
Loss on mark-to-market of derivatives, net		(387,305	)		(1,086,944	)
Gain (loss) on derivatives, net	$	728,808		$	(1,143,292	)

The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of December 31, 2020.

Settlement Period	Basis	Oil (Barrels)		Floor / Ceiling Prices ($)	Fair Value of Liability at December 31, 2020
01/01/21 - 05/31/21	NYMEX		68,247	38.00 / 44.85	$	(324,723	)
01/01/21 - 05/31/21	NYMEX		68,247	37.50 / 46.00		(269,909	)
					$	(594,632	)

The Partnership’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.

Note 7.  Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below) and has been and will be reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

The Partnership completed its best-efforts offering of common units as of the close of business on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

Under the agreement with David Lerner Associates, Inc. (the “Managing Dealer”), the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering on October 24, 2019, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).

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Prior to “Payout,” which is defined below, all distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

For the year ended December 31, 2020, the Partnership paid distributions of $1.396165 per common unit, or $15.4 million. For the year ended December 31, 2019, the Partnership paid distributions of $1.396164 per common unit, or $13.3 million.

Note 8.  Related Parties

The Class A voting members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and David S. McKenney, Chief Financial Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. The Class B non-voting members of the General Partner are affiliates of Anthony F. Keating, III and Michael J. Mallick, the Co-Chief Operating Officers of Energy 11’s general partner.

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.

The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include costs for organizing the Partnership, costs incurred in the offering of the common units and general and administrative costs. The Partnership has also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the limited partner agreement, subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. The management fee paid to the General Partner for the years ended December 31, 2020 and 2019 was approximately $1.1 million and $1.0 million, respectively. The management fee paid to the General Partner is included in General and administrative expenses on the consolidated statements of operations.

For the years ended December 31, 2020 and 2019, approximately $380,000 and $414,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership, respectively. At December 31, 2020 and 2019, approximately $90,000 and $133,000, respectively, was due to a member of the General Partner and is included in Accounts payable and accrued expenses in the consolidated balance sheets.

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On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 that gave the Partnership access to Energy 11’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs were split evenly between the two partnerships. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. Any other direct third-party costs were paid by the party receiving the services. The compensation due to the President of Energy 11’s general partner was also a shared cost between the Partnership and Energy 11 for the years ended December 31, 2020 and 2019. The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner; because the office space is shared between the Partnership and Energy 11, the monthly payments of $8,537 made in 2019 and 2020 were evenly split between the two partnerships in accordance with the cost sharing agreement. For the years ended December 31, 2020 and 2019, approximately $268,000 and $285,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and have been reimbursed to Energy 11. At December 31, 2019, approximately $85,000 was due from the Partnership to Energy 11 and is included in Accounts payable and accrued expenses in the consolidated balance sheet. In October 2020, the cost sharing agreement was terminated by the Partnership, effective December 31, 2020.

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and Energy 11, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. As described above, the Partnership currently pays the General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. Under the ASA, the General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. The General Partner has also agreed to pay the president of Energy 11’s general partner, who is an employee of the Administrator, an annual base compensation of $175,000, plus benefits, for his services that are included under the ASA.

The ASA is effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or Energy 11 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.

Note 9. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

Aggregate Capitalized Costs and Costs Incurred

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2020 and 2019 is as follows:

	2020			2019
Producing properties	$	157,212,668		$	148,370,378
Non-producing		71,093,790			71,083,790
		228,306,458			219,454,168
Accumulated depreciation, depletion and amortization		(36,136,401	)		(21,955,397	)
Net capitalized costs	$	192,170,057		$	197,498,771

For the years ended December 31, 2020 and 2019, the Partnership incurred the following costs in oil and natural gas producing activities:

	2020		2019
Property acquisition costs	$	-	$	256,536
Development costs		8,852,290		32,229,159
	$	8,852,290	$	32,485,695

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Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences 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 renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 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. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2020, 2019 and 2018.

The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2020, 2019 and 2018 have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with SEC rules and regulations along with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history.

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The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows:

	Proved Reserves
	Oil			Natural Gas			NGLs
	(Bbls)			(Mcf)			(Bbls)			Total (BOE)
December 31, 2018		20,264,440			9,962,790			1,492,085			23,416,990
Acquisition		-			-			-			-
Extensions, discoveries and other additions (1)		94,703			50,978			7,664			110,863
Revisions of previous estimates (2)		(1,047,353	)		(395,183	)		50,422			(1,062,795	)
Production		(1,129,951	)		(849,047	)		(126,760	)		(1,398,219	)
December 31, 2019		18,181,839			8,769,538			1,423,411			21,066,839
Acquisition		-			-			-			-
Extensions, discoveries and other additions (3)		954,587			668,211			122,579			1,188,535
Revisions of previous estimates (4)		(1,217,253	)		8,465,491			820,183			1,013,845
Production		(853,633	)		(924,481	)		(141,483	)		(1,149,197	)
December 31, 2020		17,065,540			16,978,759			2,224,690			22,120,022

(1)	In 2019, extensions, discoveries and other additions of 111 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(2)	Revisions to previous estimates decreased proved reserves by 1,063 MBOE. These revisions result from 804 MBOE of downward adjustments attributable to well performance, 246 MBOE of downward adjustments attributable to changes in the future drill schedule and 13 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.
(3)	In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(4)	Revisions to previous estimates increased proved reserves by 1,014 MBOE. The impact of these revisions had differing impacts to the Partnership’s oil, natural gas and NGL volumes. The revisions for oil volumes include 735 MBOE of downward adjustments attributable to well performance, 448 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019. The revisions for natural gas and NGL volumes include 1,800 MBOE of upward adjustments attributable to well performance, 443 MBOE of upward adjustments attributable to changes in the future drill schedule, and 11 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019.

In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2020 were $39.57 per barrel of oil and $1.99 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2020 were $31.82 per barrel of oil, $(2.33) per MMcf of natural gas and $3.13 per barrel of NGL. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2019 were $55.69 per barrel of oil and $2.58 per MMcf of natural gas, before price differentials. Including the effect of average price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2019 were $49.42 per barrel of oil, $(1.61) per MMcf of natural gas and $2.74 per barrel of NGL.

Net quantities of proved developed and proved undeveloped reserves at December 31, 2020, 2019 and 2018 are summarized in the table below.

	Oil		Natural Gas		NGLs
	(Bbls)		(Mcf)		(Bbls)		Total (BOE)
Proved developed reserves:
December 31, 2018		6,982,216		4,126,780		686,765		8,356,778
December 31, 2019		6,986,035		4,733,090		774,311		8,549,194
December 31, 2020		6,881,782		9,202,098		1,210,323		9,625,787
Proved undeveloped reserves:
December 31, 2018		13,282,224		5,836,010		805,320		15,060,212
December 31, 2019		11,195,804		4,036,448		649,100		12,517,645
December 31, 2020		10,183,758		7,776,661		1,014,367		12,494,235

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The following details the changes in proved undeveloped reserves (PUD) for 2019 and 2020 (in BOE):

	BOE
Proved undeveloped reserves, December 31, 2018		15,060,212
Revisions of previous estimates (1)		(401,688	)
Extensions, discoveries and other additions (2)		52,367
Conversion to proved developed reserves (3)		(2,193,246	)
Proved undeveloped reserves, December 31, 2019		12,517,645
Revisions of previous estimates (4)		697,585
Extensions, discoveries and other additions (5)		1,188,535
Conversion to proved developed reserves (6)		(1,909,530	)
Proved undeveloped reserves, December 31, 2020		12,494,235

(1)	The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019, and 9 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.
(2)	In 2019, extensions, discoveries and other additions of 52 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(3)	The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE.
(4)	The annual review of the PUDs resulted in a positive revision of approximately 698 MBOE. This revision was the result of 724 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2019, 21 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, and 5 MBOE of downward adjustments attributable to changes in the future drill schedule.
(5)	In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(6)	The Partnership converted 34 wells to proved developed reserves during 2020 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 1,909 MBOE.

The Partnership anticipates all current PUD locations will be drilled and converted to PDP within five years of the date they were added. PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves have been removed as revisions at the time that determination was made.

Standardized Measure of Discounted Future Net Cash Flows

Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

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	2020			2019
	(in thousands)			(in thousands)
Future cash inflows	$	510,534		$	888,271
Future production costs		(233,563	)		(244,165	)
Future development costs		(83,551	)		(88,056	)
Future net cash flows		193,420			556,050
10% annual discount		(125,407	)		(312,901	)
Standardized measure of discounted future net cash flows	$	68,013		$	243,149

Changes in the standardized measure of discounted future net cash flows are as follows:

	2020			2019
	(in thousands)			(in thousands)
Standardized measure at beginning of period	$	243,149		$	370,495
Changes resulting from:
Acquisition of reserves		-			-
Extensions, discoveries and other additions		7,889			1,093
Sales of oil, natural gas and NGLs, net of production costs		(16,534	)		(41,631	)
Net changes in prices and production costs		(149,606	)		(97,776	)
Development costs incurred during the period		8,852			32,229
Revisions to previous estimates		(45,739	)		(40,287	)
Accretion of discount		24,349			37,101
Change in estimated future development costs		(4,347	)		(18,075	)
Standardized measure of discounted future net cash flows	$	68,013		$	243,149

Note 10.  Quarterly Financial Data (Unaudited)

The following is a summary of quarterly results of operations for the years ended December 31, 2020 and 2019. Net income per common unit is non-additive in comparison to net income per common unit for each year due to the timing and size of the Partnership’s common unit issuances.

	2020
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
Total revenue	$	11,932,896		3,189,431			7,903,439			11,888,952
Net income (loss)	$	2,214,315		(2,824,856	)		(76,659	)		1,398,501
Basic and diluted net income (loss) per common share	$	0.20		(0.26	)		(0.01	)		0.13

	2019
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Total revenue	$	11,361,830	$	18,832,114	$	15,883,884	$	18,352,989
Net income	$	1,641,943	$	8,277,089	$	5,680,657	$	2,741,099
Basic and diluted net income per common share	$	0.20	$	0.92	$	0.56	$	0.25

Note 11.  Subsequent Events

In January 2021, the Partnership declared and paid $1.5 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.

In February 2021, the Partnership declared and paid $1.2 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

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Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of the General Partner concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2020 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

The Partnership’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. The Partnership has performed an evaluation under the supervision and with the participation of its management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s internal control over financial reporting. The Partnership’s management assessed the effectiveness of its internal control over financial reporting as of December 31, 2020. The Partnership’s management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) to perform its assessment. Based on this assessment, the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer of the General Partner, concluded, that as of December 31, 2020, the Partnership’s internal control over financial reporting was effective based on those criteria.

Changes in Internal Control Over Financial Reporting

There has been no change in the Partnership’s internal control over financial reporting during the quarter ended December 31, 2020 that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Item 9B.  Other Information

None

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Part III

Item 10.  Directors, Executive Officers, and Corporate Governance

Directors and Executive Officers of the General Partner

As is the case with many partnerships, the Partnership does not directly employ officers, directors or employees. Its operations and activities are managed by the Board of Directors and executive officers of the General Partner. References to the Partnership’s directors and executive officers are references to the directors and executive officers of the General Partner.

The following table sets forth the names, ages and offices of the present directors and executive officers of the General Partner as of December 31, 2020:

Name	Age	Position
Glade M. Knight	76	Director and Chief Executive Officer
David S. McKenney	58	Director and Chief Financial Officer and Secretary

The following is a biographical summary of the business experience of these directors and executive officers:

Glade M. Knight. Mr. Knight has been part owner of and the Chief Executive Officer of the General Partner since its formation in December 2016. Mr. Knight is also a part owner of and the Chief Executive Officer of Energy 11 GP, LLC, the general partner of Energy 11, a partnership also focused on investments in the oil and gas industry. Mr. Knight is the founder and has served as Executive Chairman of Apple Hospitality REIT, Inc. since May 2014, and previously served as Chairman and Chief Executive Officer since its inception. Mr. Knight was also the founder of each of the former Apple REIT Companies and served as their Chairman and Chief Executive Officer from inception until the companies were sold to a third party or merged with Apple Hospitality REIT, Inc. In addition, Mr. Knight served as Chairman and Chief Executive Officer of Cornerstone Realty Income Trust, Inc. from 1993 until it merged with a subsidiary of Colonial Properties Trust in 2005. Following the merger in 2005 until April 2011, Mr. Knight served as a trustee of Colonial Properties Trust. Cornerstone Realty Income Trust, Inc. owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. Mr. Knight is the founding Chairman of Southern Virginia University in Buena Vista, Virginia. He also is a member of the Advisory Board to the Graduate School of Real Estate and Urban Land Development at Virginia Commonwealth University. Additionally, he serves on the National Advisory Council for Brigham Young University and is a founding member of the University’s Entrepreneurial Department of the Graduate School of Business Management. On February 12, 2014, Mr. Knight, Apple REIT Seven, Inc. (“Apple Seven”), Apple REIT Eight, Inc. (“Apple Eight”), Apple REIT Nine, Inc. (“Apple Nine”) and their related advisory companies entered into settlement agreements with the SEC. Along with Apple REIT Seven, Apple REIT Eight, Apple REIT Nine and their advisory companies, and without admitting or denying the SEC’s allegations, Mr. Knight consented to the entry of an administrative order, under which Mr. Knight and the noted companies each agreed to cease and desist from committing or causing any violations of Sections 13(a), 13(b)(2)(A), 13(b)(2)(B), 14(a), and 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Rules 12b-20, 13a-1, 13a-13, 13a-14, 14a-9, and 16a-3 thereunder.

David S. McKenney. Mr. McKenney has been part owner of and the Chief Financial Officer of the General Partner since its formation in December 2016. Mr. McKenney is also a part owner of and the Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, a partnership also focused on investments in the oil and gas industry. Mr. McKenney was the President of Capital Markets of Apple REIT Ten, Inc. from its inception until it merged with Apple Hospitality REIT, Inc. in September 2016. Mr. McKenney previously served as President of Capital Markets for Apple Hospitality REIT, Inc. In addition, Mr. McKenney was the President of Capital Markets of Apple REIT Six, Inc., a real estate investment trust, from 2004 until the company merged with an affiliate of Blackstone Real Estate Partners VII in May 2013. Mr. McKenney served in the same capacity for Apple Hospitality Five, Inc., a lodging REIT, from 2002 until the company was sold to Inland American Real Estate Trust, Inc. in October of 2007, and Apple Hospitality Two, Inc., a lodging REIT, from 2001 until the company was sold to an affiliate of ING Clarion in May of 2007. From 1994 to 2001, Mr. McKenney served as Senior Vice President and Treasurer of Cornerstone Realty Income Trust, Inc., a REIT that owned and operated apartment communities in Virginia, North Carolina, South Carolina, Georgia and Texas. From 1992 to 1994, Mr. McKenney served as Chief Financial Officer for The Henry A. Long Company, a regional development firm located in Washington, D.C. From 1988 to 1992, Mr. McKenney served as a Controller at Bozzuto & Associates, a regional developer of apartments and condominiums in the Washington, D.C. area. Mr. McKenney holds Bachelor of Science degrees in Accounting and Management Information Systems from James Madison University.

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The General Partner

The General Partner is Energy Resources 12 GP, LLC, which was formed in 2016 and has no operating history. The General Partner was formed and its Class A voting units are controlled by companies controlled by Glade M. Knight and David S. McKenney. The General Partner’s Class B non-voting units are controlled by companies controlled by Anthony F. Keating III and Michael J. Mallick.

The General Partner receives a management fee for acting as general partner, as defined below. In addition, the Partnership has or will reimburse the General Partner and its affiliates for all general and administrative expenses incurred by the General Partner and its affiliates in managing the Partnership’s business. These costs and expenses will include the direct and indirect costs and expenses of employee compensation, rental, office supplies, travel and entertainment, printing, legal, accounting, advertising, marketing and overhead. The beneficial owners of the General Partner will not be employees of the General Partner and will not receive salary or other compensation from the General Partner or the Partnership other than the reimbursement of third-party costs and expenses, the management fee described below, and with respect to their equity interests in the Partnership.

As described in the Prospectus, upon the Partnership’s first property acquisition, the Partnership is obligated to pay quarterly an annual management fee of 0.5% of the total gross equity proceeds raised in this offering to the General Partner. The fees and expenses paid to the General Partner are in exchange for:

● Administering the day-to-day operations of the Partnership and performing or supervising the various administrative functions necessary to manage the Partnership;

● Identifying producing and non-producing properties for potential acquisition, and evaluating, contracting for and acquiring these properties and managing the development of these properties; and

● Monitoring or hiring a third party to monitor the operator(s) of the properties the Partnership acquires, including recommending whether the Partnership should participate in the development of such properties by the operators of the properties.

With the Partnership’s closing on the purchase of certain non-operated oil and gas properties in North Dakota on February 1, 2018, the Partnership began payment of the management fee at the end of the first quarter of 2018. The management fee paid to the General Partner for the years ended December 31, 2020 and 2019 was approximately $1.1 million and $1.0 million, respectively.

Code of Ethics

The General Partner has adopted a Code of Business Conduct and Ethics that applies to the executive officers of the General Partner and other persons performing services for the General Partner and the Partnership, generally. This Code of Business Conduct and Ethics is posted on the Partnership’s website at www.energyresources12.com.

Audit and Compensation Committee

The Partnership does not have a formal compensation committee and the Board of Directors of the General Partner serves as the audit committee. Because the Partnership does not have and is not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, the Partnership is not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, the Partnership is not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, the Board of Directors has not made any determination as to whether any of the member of the Board of Directors would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, the Partnership has not yet determined whether any of the directors is an audit committee financial expert.

Item 11.  Executive Compensation

The Partnership does not directly employ any of the persons responsible for managing its business. Instead, the General Partner manages the Partnership’s day-to-day affairs and provides the Partnership with management and operating services. The members of the General Partner have been or will be reimbursed for documented out-of-pocket travel, entertainment and similar expenses incurred by them in connection with managing the Partnership’s business. The executive officers of the General Partner did not receive any salary, bonus or consulting fees for serving on the board of directors or for managing the Partnership’s business for the years ended December 31, 2020 and 2019, other than the approximate $1.1 million and $1.0 million management fee (described above) paid to the General Partner by the Partnership, and distributions in accordance with the incentive distribution rights and their ownership of common units, if any.

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Outstanding Equity Awards at Fiscal Year-End

There were no outstanding equity awards for the Partnership’s named executive officers as of December 31, 2020 and 2019, other than the Incentive Distribution Rights.

Compensation of Directors

The members of the General Partner do not receive compensation for their services as directors, aside from the management fee described in section “The General Partner” in Part III, Item 10 of this Form 10-K.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth as of March 1, 2021 the beneficial ownership of the common units that are owned by:

● all persons who, to the knowledge of the management team, beneficially own more than 5% of the Partnership’s common units;

● each executive officer of the General Partner; and

● all current directors and executive officers of the General Partner as a group.

Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned
Glade M. Knight 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*
David S. McKenney 120 W. 3rd Street, Suite 220 Fort Worth, Texas 76102		5,000		*
Directors and executive officers of the General Partner as a group		10,000		*

* Less than 1% of outstanding common units.

Ownership of the General Partner

The General Partner is a limited liability company. The members of the General Partner and the membership interest owned are as follows:

● GKOG, LLC, owns a 50% Class A (voting) membership interest in the General Partner. GKOG, LLC is a limited liability company owned by Mr. Knight and members of his immediate family.

● DMOG, LLC owns a 50% Class A (voting) membership interest in the General Partner. DMOG, LLC is a limited liability company wholly owned by Mr. McKenney and members of his immediate family.

● CFK Energy, LLC owns a Class B (non-voting) membership interest in the General Partner. CFK Energy, LLC is a limited liability company wholly owned by Anthony F. Keating, III and members of his immediate family. Mr. Keating is the Co-COO of Energy 11 GP, LLC, the general partner of Energy 11, L.P.

● Pope Energy Investors, LP owns a Class B (non-voting) membership interest in the General Partner. Pope Energy Investors, LP is a limited partnership wholly owned by Mr. Mallick and members of his immediate family. Mr. Mallick is the Co-COO of Energy 11 GP, LLC, the general partner of Energy 11, L.P.

Each Class A member of the General Partner has the right to appoint one person to the General Partner’s Board of Directors. All decisions regarding the business of the General Partner and the Partnership will be made by the Board of Directors of the General Partner at meetings of the Board of Directors at which a quorum is present. The presence of a majority of the directors constitutes a quorum, and the vote of a majority of a quorum constitutes a decision by the Board of Directors.

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General Partner Class A Units

The owners of the members of the General Partner have granted each other the right of first refusal to acquire any interests in the members of the General Partner that the owners propose to sell. If the owners of the members of the General Partner do not exercise the right of first refusal, the purchaser of the owner of the General Partner will have the right to appoint a member to the board of directors, and if a person or group of affiliated persons were to acquire a controlling interest in both of the owners of the General Partner, the person would be able to control the General Partner and the Partnership. The Partnership Agreement does not give the holders of common units the right to cause an owner of the General Partner to exercise its buy-sell right or provide the holders the right to consent to or otherwise approve the transfer by an owner of the General Partner of its membership interest in the General Partner. The General Partner does, however, agree not to permit a change of control of the General Partner to occur. A change of control is defined as a person who is not currently a beneficial owner of the General Partner or a “qualifying owner” becoming the beneficial owner of 50% or more of the membership interest in the General Partner. A qualifying owner generally is defined as the following with respect to the current beneficial owners of the General Partner: conservators, guardians, executors, administrators, and similar persons of any trust, private foundation or custodianship that such beneficial owner, his spouse, lineal descendants or estate is a beneficiary.

General Partner Class B Units

In November 2017 and June 2018, the Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing, financing and post-closing on its two 2018 acquisitions of oil and gas assets in North Dakota (the “Bakken Assets”). Under the advisory and administration agreements (the “Agreements”), REI was entitled to a fee of 5% of the gross sales price in the event the Partnership disposed of any or all of the Bakken Assets, if surplus funds were available after Payout, to the holders of the Partnership’s common units.

On December 28, 2018, the Partnership terminated its Agreements with REI, which extinguished any potential fee upon sale of certain of the Partnership’s assets as was required under the Agreements. At the time of the extinguishment, the payment of a fee was not probable and there was no value to the rights owned by REI. In connection with the termination, the General Partner issued 500 of its Class B Units to each of Pope Energy Investors, LP and CFK Energy, LLC. The General Partner received $250 from each of Pope Energy Investors, LP and CFK Energy, LLC for this transaction. The General Partner Class B Units are non-voting and participate in 50% of any distributions by the General Partner from proceeds of its Incentive Distribution Rights, after Payout and the Dealer Manager Incentive Fees are paid, as defined in Note 7. Capital Contributions and Partners’ Equity of Part II, Item 8 of this Form 10-K.

CFK Energy, LLC is owned by an entity that is controlled by Anthony F. Keating, III, Co-Chief Operating Officer of Energy 11 GP, LLC, and Pope Energy Investors, LP is owned by an entity that is controlled by Michael J. Mallick, Co-Chief Operating Officer of Energy 11 GP, LLC. Energy 11 GP, LLC is the general partner of Energy 11, L.P. REI is also owned by entities that are controlled by Messrs. Keating and Mallick.

The General Partner continues to be controlled and managed by the Class A voting units of the General Partner, which are owned by entities controlled by Messrs. Knight and McKenney, the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner.

Securities Authorized for Issuance under Equity Compensation Plans

The Partnership does not have any equity compensation plans.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

Reimbursement of Expenses to General Partner in Connection with Operations of the Partnership

The Partnership has or will reimburse the General Partner and the General Partner’s affiliates for their General and administrative costs allocable to the Partnership. These expenses will include compensation expense, rent, travel, and other general and administrative and overhead expenses. Currently, the only business of the General Partner is to act as General Partner of the Partnership, and all of the General Partner’s general and administrative costs will be paid by the Partnership. If affiliates of the General Partner form other partnerships or engage in other oil and gas activities, the General Partner will allocate its general and administrative costs to the Partnership and other partnerships or businesses in a manner deemed reasonable by the General Partner.

During the years ended December 31, 2020 and 2019, approximately $380,000 and $414,000 of related party costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership in connection with its operations. At December 31, 2020 and 2019, approximately $90,000 and $133,000 was due to a member of the General Partner.

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Management Fee

The Partnership has agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the Partnership Agreement, subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. The management fee paid to the General Partner for the years ended December 31, 2020 and 2019 was approximately $1.1 million and $1.0 million, respectively.

Incentive Distribution Rights

On the initial closing date, the Partnership issued incentive distribution rights, which are non-voting limited partner interests that entitle the holder of such rights, after Payout occurs, to 30% of all amounts distributed until the Managing Dealer receives 4% of the gross proceeds of the common units sold, and to 60% of all amounts distributed thereafter, to the General Partner.

Cost Sharing Agreement

On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11, L.P. (“Energy 11”) that gave the Partnership access to Energy 11’s president, personnel and administrative resources. The personnel provide accounting, asset management and other day-to-day management support for both partnerships. The shared day-to-day costs were split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. For the years ended December 31, 2020 and 2019, approximately $268,000 and $285,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and have been reimbursed to Energy 11. The agreement was terminated by the Partnership in October 2020, effective December 31, 2020.

Administrative Services Agreement

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and Energy 11, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. As described above, the Partnership currently pays the General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. Under the ASA, the General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. The Administrator owned by entities that are controlled by Anthony F. Keating, III and Michael J. Mallick. Messrs. Keating and Mallick are the Co-Chief Operating Officers of Energy 11 GP, LLC, and entities controlled by Messrs. Keating and Mallick are Class B, non-voting members of the General Partner.

Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. The General Partner has also agreed to pay the president of Energy 11’s general partner, who is an employee of the Administrator, an annual base compensation of $175,000, plus benefits, for his services that are included under the ASA.

The ASA is effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or Energy 11 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.

Director Independence

Because the Partnership does not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, the Partnership is not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, the Board of Directors of the General Partner has not made any determination as to whether any non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

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Item 14.  Principal Accountant Fees and Services

Ernst & Young LLP (“EY”), as the Partnership’s independent registered public accounting firm, has audited the Partnership’s consolidated financial statements for the most recent fiscal year ended December 31, 2020. EY was selected and appointed as the Partnership’s independent registered public accounting firm in 2017.

For the fiscal years ended December 31, 2020 and 2019, fees paid or payable to EY for services performed in connection with the audit of the 2020 financial statements, the audit of the 2019 financial statements, reviews of S-1s and any amendments, SEC comment letters, issuance of consents and 2020 and 2019 interim reviews are as follows:

	Year Ended December 31, 2020		Year Ended December 31, 2019
Audit fees	$	200,000	$	305,000
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
Total	$	200,000	$	305,000

Pre-Approval Policies and Procedures

The General Partner currently has no Board committees. The Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services provided by the independent public accountants and reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled meetings. All of the services provided by EY during the years ended December 31, 2020 and 2019 were approved by the Board of Directors.

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Part IV

Item 15.  Exhibits and Financial Statement Schedules

(a) Documents filed as part of this report:

1. Financial Statements:

(i) Report of Independent Registered Public Accounting Firm – Ernst & Young LLP

(ii) Consolidated Balance Sheets as of December 31, 2020 and December 31, 2019

(iii) Consolidated Statements of Operations for the years ended December 31, 2020 and 2019

(iv) Consolidated Statements of Partners’ Equity for the years ended December 31, 2020 and 2019

(v) Consolidated Statements of Cash Flows for the years ended December 31, 2020 and 2019

(vi) Notes to Consolidated Financial Statements

2. Financial Statement Schedules:

(i) All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

3. Exhibits:

The following exhibits are included, or incorporated by reference, in this Annual Report on Form 10-K, for the year ended December 31, 2020 (and are numbered in accordance with Item 601 of Regulation S-K). Exhibits incorporated by reference to this Form 10-K as listed below are available at www.sec.gov.

Exhibit No.	Description
1.1	Exclusive Dealer Manager Agreement with David Lerner Associates, Inc. (incorporated by reference from Exhibit 1.1 to Pre-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 filed on April 18, 2017).
2.1	Purchase and Sale Agreement dated November 21, 2017 by and between Energy Resources 12 Operating Company, LLC, as Purchaser, and Bruin E&P Non-Op Holdings, LLC, as Seller (incorporated by reference from Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed on November 22, 2017).
2.2	Purchase and Sale Agreement dated June 29, 2018 by and between Energy Resources 12 Operating Company, LLC, as Purchaser, and Bruin E&P Non-Op Holdings, LLC, as Seller (incorporated by reference from Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed on July 6, 2018).
3.1	Certificate of limited partnership of Energy Resources 12, L.P. (incorporated by reference from Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 filed on March 23, 2017).
3.2	First Amended and Restated Limited Partnership Agreement of Energy Resources 12, L.P. (incorporated by reference from Exhibit A to the Prospectus included as part of Post-Effective Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 filed on February 1, 2018).
4.1	Description of Securities Registered Under Section 12 of the Exchange Act*
10.1	Administrative Services Agreement, dated December 1, 2020 and effective as of January 1, 2021, by and between Regional Energy Investors, L.P. d/b/a Regional Energy Management, Energy 11, L.P., Energy 11 Operating Company, LLC, Energy Resources 12, L.P. and Energy Resources 12 Operating Company, LLC (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on December 3, 2020)
21.1	Subsidiaries of the Partnership*

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31.1	Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
32.1	Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2	Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
99.1	Report of Pinnacle Energy Services, LLC, Independent Petroleum Consultants.*
101	The following materials from Energy Resources 12, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2020 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) Consolidated Statement of Cash Flows, and (v) related notes to these consolidated financial statements, tagged as blocks of text and in detail*
104	The cover page from the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020, formatted in iXBRL and contained in Exhibit 101

*Filed herewith.

Item 16.  Form 10-K Summary

None

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENERGY RESOURCES 12, L.P. By: Energy Resources 12 GP, LLC, its General Partner
By:	/s/ David S. McKenney
	David S. McKenney
	Chief Financial Officer

Date: March 17, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title with General Partner	Date
/s/ Glade M. Knight	Director, Chief Executive Officer	March 17, 2021
Glade M. Knight	(principal executive officer)
/s/ David S. McKenney	Director, Chief Financial Officer	March 17, 2021
David S. McKenney	(principal financial and accounting officer)

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EX-4.1

EXHIBIT 4.1

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

The following summary of the securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 of Energy Resources 12, L.P. (the “Partnership”) is based on and qualified by the Partnership’s First Amended and Restated Limited Partnership Agreement (“Partnership Agreement”). The following summary does not purport to be complete and is subject to and qualified in its entirety by reference to the Partnership Agreement, which is incorporated by reference as Exhibit 3.2 to the Annual Report on Form 10-K of which this Exhibit 4.1 is a part. The Partnership encourages you to read the Partnership Agreement and the applicable provisions of the Delaware Revised Uniform Limited Partnership Act (“Delaware Act”) for additional information.

General

The Partnership Agreement provided for the offering and sale of up to 17,631,579 common units. On July 25, 2017, the Incentive Distribution Rights were issued to the Partnership’s general partner. The Partnership Agreement authorizes the Partnership’s general partner, without approval of common unit holders, to amend certain parts of the Partnership Agreement, in whole or in part, within the limits set forth in the Partnership Agreement and under Delaware law.

David Lerner Associates, Inc. (the “Dealer Manager”) was the dealer manager for the offering of the Partnership’s common units. Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager may also be paid Dealer Manager Incentive Fees (after Payout, discussed below), which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold through the best-efforts offering, the total contingent fee is a maximum of approximately $8.7 million.

Common units

Units issued and outstanding – 11,031,579 common units.

Voting – see “Voting Rights” below for more information.

Distributions – holders of the common units are entitled to receive proportionately any dividends if, and when, such dividends are declared by the Partnership.

Other rights – the common units do not have a sinking fund or redemption provisions or preemptive, conversion or exchange rights.

Incentive Distribution Rights (IDRs)

Voting – subject to the provisions of Partnership Agreement, a holder of IDRs does not have the right to vote on Partnership matters, except with respect for amendments to the Partnership Agreement that would adversely affect such IDR interests, in which case a holder of IDRs will have a right to vote thereon as a separate class.

Distributions – the Partnership will not make any distributions with respect to the IDRs until Payout occurs. See below for the distribution rights of holders of IDRs after Payout.

Rights at Payout

The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

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● First, (i) to the record holders of the Incentive Distribution Rights, 30%; (ii) to the Dealer Manager, the “Dealer Manager Incentive Fees”, 30%, until such time as the Dealer Manager receives 4% of the gross proceeds of the common units sold; and (iii) to the record holders of outstanding common units, 40%, pro rata based on their percentage interest;

● Thereafter, (i) to the record holders of the Incentive Distribution Rights, 60%; and (ii) to the record holders of outstanding common units, 40%, pro rata based on their percentage interest.

The information below further summarizes certain sections of the Partnership Agreement to address the rights of the holders of the common units.

Purpose

The purpose under the Partnership Agreement is limited to any business activity that is approved by the general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that the general partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the general partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Power of Attorney

Each limited partner, and each person who acquires a common unit from a common unitholder, by accepting the common unit, automatically grants to the general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for the Partnership’s qualification, continuance or dissolution. The power of attorney also grants the general partner the authority to amend, and to make consents and waivers under, the Partnership Agreement.

Capital Contributions

Common unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability”. The general partner will make only a nominal capital contribution to the Partnership. No cash capital contributions will be made with respect to the IDRs.

Voting Rights

The following is a summary of the voting rights of the holders of common units. A common unit majority is a vote or consent by the holders of a majority of the common units then outstanding.

Amendment of the Partnership Agreement	Certain amendments may be made by the general partner without the approval of the common unitholders. Other amendments generally require the approval of the holders of a majority of the common units (including common units held by the general partner and its affiliates) which the Partnership refers to as a “common unit majority.”
Merger of the Partnership or the sale of all or substantially all of its assets	Common unit majority and the holder of a majority of the IDRs in certain circumstances.
Dissolution of the Partnership	Common unit majority
Continuation of the Partnership’s business upon dissolution	Common unit majority
Withdrawal of the general partner	The general partner does not have the right to withdraw as the general partner without the consent of the holders of a majority of the common units other than common units owned by the general partner and its affiliates.
Removal of the general partner	Holders of the common units do not have the right to remove the general partner.

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Transfer of the general partner interest	The general partner may transfer all, but not less than all, of its general partner interest in the Partnership without a vote of the common unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party.
Transfer of incentive distribution rights	The general partner has agreed not to transfer the incentive distribution rights prior to October 24, 2022.
Transfer of ownership interests in the general partner	The general partner has agreed that it will not permit a change of control of the general partner to occur.

Limited Liability

Assuming that a limited partner does not participate in the control of the Partnership’s business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the Partnership Agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to the Partnership for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

● to approve some amendments to the Partnership Agreement; or

● to take other action under the Partnership Agreement;

constituted “participation in the control” of the Partnership’s business for the purposes of the Delaware Act, then the limited partners could be held personally liable for the Partnership’s obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with the Partnership who reasonably believe that the limited partner is a general partner. Neither the Partnership Agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, the Partnership knows of no precedent for this type of a 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.

The Partnership’s subsidiaries conduct business in states other than Delaware. Maintenance of the Partnership’s limited liability as an owner of its subsidiaries may require compliance with legal requirements in the jurisdictions in which the subsidiaries conduct business, including qualifying the Partnership’s subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of the Partnership’s interest in its subsidiaries or otherwise, it were determined that the Partnership 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 the limited partners as a group to approve some amendments to the Partnership Agreement, or to take other action under the Partnership Agreement constituted “participation in the control” of the Partnership’s business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for the Partnership’s obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. The Partnership will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

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Amendment of the Partnership Agreement

General

Amendments to the Partnership Agreement may be proposed only by or with the consent of the general partner. However, the 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 the Partnership or the limited partners, including any duty to act in good faith or in the best interests of the Partnership or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, the general partner is required to seek written approval of the holders of the number of common units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a common unit majority.

Prohibited Amendments

No amendment may be made that would:

● enlarge the obligations of any limited partner without its consent; or

● 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 the Partnership to the general partner or any of its affiliates without the consent of the general partner, which consent may be given or withheld at its option; or

● materially adversely affect the rights of the holders of IDRs without the consent of the holders of a majority of IDRs, as applicable; provided that if such amendment to the Partnership Agreement is made in connection with a Liquidity Event, such consent by the holders of IDRs may not be unreasonably withheld.

No Common Unitholder Approval

The general partner may generally make amendments to the Partnership Agreement without the approval of any limited partner or assignee to reflect:

● a change in the Partnership’s name, the location of its principal place of its business, its registered agent or its registered office;

● the admission, substitution, withdrawal or removal of partners in accordance with the Partnership Agreement;

● a change that the general partner determines to be necessary or appropriate to qualify or continue the Partnership’s qualification 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 neither the Partnership nor its wholly-owned operating subsidiary will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

● an amendment that is necessary, in the opinion of the Partnership’s counsel, to prevent the Partnership or the general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA;

● any amendment expressly permitted in the Partnership Agreement to be made by the general partner acting alone;

● an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the Partnership Agreement;

● any amendment that the general partner determines to be necessary or appropriate for the formation by Partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by the Partnership Agreement;

● a change in the Partnership’s fiscal year or taxable year and related changes;

● 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

● any other amendments substantially similar to any of the matters described in the clauses above.

In addition, the general partner may make amendments to the Partnership Agreement without the approval of any limited partner if the general partner determines that those amendments:

● do not adversely affect the 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;

● are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

● are necessary or appropriate for any action taken by the general partner relating to splits or combinations of common units under the provisions of the Partnership Agreement; or

● are required to effect the intent expressed in the prospectus describing the public offering of common units or the intent of the provisions of the Partnership Agreement or are otherwise contemplated by the Partnership Agreement.

Opinion of Counsel and Common Unitholder Approval.

The general partner will not be required to obtain an opinion of counsel that an amendment proposed by the general partner will not result in a loss of limited liability to the limited partners or result in the Partnership being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to the Partnership Agreement will become effective without the approval of holders of at least 90% of the outstanding common units voting as a single class unless the Partnership first obtains an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of the Partnership’s limited partners.

Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding common units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of the Partnership requires the prior consent of the general partner. However, the 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 the Partnership or the limited partners, including any duty to act in good faith or in the best interest of the Partnership or the limited partners.

In addition, the Partnership Agreement generally prohibits the general partner without the prior approval of the holders of a common unit majority from causing the Partnership to, among other things, sell, exchange or otherwise dispose of all or substantially all of the Partnership’s assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on its behalf the sale, exchange or other disposition of all or substantially all of the assets of the Partnership’s subsidiaries. In addition, if the sale of assets or merger, consolidation or other combination would result in an amendment to the Partnership Agreement that is materially adverse to the holders of IDRs, the sale of assets, merger, consolidation or other combination will require approval of the holders of a majority of IDRs, as the case may be, which approval may not be unreasonably withheld. The general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the Partnership’s assets without that approval. The general partner may also sell all or substantially all of the Partnership’s assets under a foreclosure or other realization upon those encumbrances without that approval.

If the conditions specified in the Partnership Agreement are satisfied, the general partner may convert the Partnership or any of its subsidiaries into a new limited liability entity or merge it or any of its subsidiaries into, or convey all of the Partnership’s assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in its legal form into another limited liability entity, the general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the Partnership Agreement. The common unitholders are not entitled to dissenters’ rights of appraisal under the Partnership Agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of the Partnership’s assets or any other similar transaction or event.

Termination and Dissolution

The Partnership will continue as a limited partnership until terminated under the Partnership Agreement. The Partnership will dissolve upon:

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● the election of the general partner to dissolve the Partnership, if approved by the holders of common units representing a common unit majority;

● there being no limited partners, unless the Partnership is continued without dissolution in accordance with applicable Delaware law;

● at any time after 90% of the net proceeds from the sale of common units (after deduction of sales commissions, marketing fees and offering and organization expenses) have been invested, the election of the general partner to cause the Partnership to dissolve at any time that the present value of its after tax cash flows, discounted at 10%, from estimated net proved reserves at the end of any year falls below 20% of the net proceeds from our sale of common units;

● the entry of a decree of judicial dissolution of this partnership; or

● the withdrawal or removal of the general partner or any other event that results in its ceasing to be the general partner other than by reason of a transfer of its general partner interest in accordance with the Partnership Agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a common unit majority may also elect, within specific time limitations, to continue the Partnership’s business on the same terms and conditions described in the Partnership Agreement by appointing as a successor general partner an entity approved by the holders of common units representing a common unit majority, subject to the Partnership’s receipt of an opinion of counsel to the effect that:

● the action would not result in the loss of limited liability of any limited partner; and

● neither the Partnership, nor its wholly-owned operating subsidiary would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon the Partnership’s dissolution, unless the Partnership is continued as a new limited partnership, the liquidator authorized to wind up the Partnership’s affairs will, acting with all of the powers of the general partner, take such actions that are necessary or appropriate to liquidate the Partnership’s assets and apply the proceeds of the liquidation in the same manner that the Partnership distributes cash at the end of each quarter. The liquidator may defer liquidation or distribution of the Partnership’s 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 its partners.

Withdrawal or Removal of the General Partner

The general partner may not withdraw as general partner without the consent of holders of a majority of the common units, other than common units held by the general partner and its affiliates.

Upon withdrawal of the general partner under any circumstances, other than as a result of a transfer by the general partner of all or a part of its general partner interest in the Partnership, the holders of a common unit majority may select a successor to the 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, the Partnership will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a common unit majority agree in writing to continue the Partnership’s business and to appoint a successor general partner.

The general partner may not be removed by the holders of common units.

Transfer of General Partner Interest

Except for transfer by the general partner of all, but not less than all, of its general partner interest to:

● an affiliate of the general partner (other than an individual); or

● another entity as part of the merger or consolidation of the general partner with or into another entity or the transfer by the general partner of all or substantially all of its assets to another entity,

6

the general partner may not transfer its general partner interest in the Partnership without the consent of a common unit majority. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of the general partner, agree to be bound by the provisions of the Partnership Agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

The general partner and its affiliates may at any time, transfer common units to one or more persons, without common unitholder approval.

Transfer of Ownership Interests in the General Partner

The general partner has agreed not to undergo a change of control. A change of control is defined as any person or group of persons, other than “qualifying owners”, acquiring beneficial ownership of 50% or more of the outstanding membership interests in the general partner. A qualifying owner is generally defined as the current beneficial owners of the general partner and any conservator, guardian or similar person of such existing beneficial owner, and any trust, foundation or similar organization the beneficiaries of which include the existing beneficial owner.

Transfer of Incentive Distribution Rights

The general partner or its affiliates or a subsequent holder may transfer its IDRs to an affiliate of the holder or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the holders of a majority of the common units. The general partner may also transfer its IDRs to managers, officers and/or employees of the general partner and to managers, officers and/or employees of the members of the general partner. The general partner may not otherwise transfer the IDRs for three years following October 24, 2019, the final closing date, without the consent of a unit majority.

Meetings; Voting

Record holders of common units on the record date will be entitled to notice of, and to vote at, meetings of the limited partners and to act upon matters for which approvals may be solicited.

The general partner does not anticipate that any meeting of common unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the common unitholders may be taken either at a meeting of the common unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of common units necessary to authorize or take that action at a meeting. Meetings of the common unitholders may be called by the general partner or by common unitholders owning at least 20% of the outstanding common units. Common unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding common units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the common unitholders requires approval by holders of a greater percentage of the common units, in which case the quorum will be the greater percentage.

Each record holder of a common unit has one vote. Common units held in nominee or 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 the Partnership Agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with the 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 is reflected in the Partnership’s books and records. Except as described under “— Limited Liability” , the common units will be fully paid, and common unitholders will not be required to make additional contributions.

7

Non-Citizen Assignees; Redemption

If the Partnership is or becomes subject to federal, state or local laws or regulations that, in the reasonable determination of the general partner, create a substantial risk of cancellation or forfeiture of any property that the Partnership has an interest in because of the nationality, citizenship or other related status of any limited partner, the Partnership may redeem the common units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, the general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or the general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from the Partnership, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his common units and may not receive distributions in-kind upon our liquidation.

Indemnification

The Partnership will indemnify the following persons under the Partnership Agreement:

● The general partner,

● Any former general partner, and

● Any director, officer, member, partner, fiduciary or trustee of any of the foregoing entities.

Any indemnification under these provisions will only be out of the Partnership’s assets. Unless it otherwise agrees, the general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to the Partnership to enable it to effectuate, indemnification. The Partnership may purchase insurance against liabilities asserted against and expenses incurred by persons for its activities, regardless of whether it would have the power to indemnify the person against liabilities under the Partnership Agreement.

Governing Law, Venue and Jurisdiction

The Partnership Agreement is governed by the laws of the State of Delaware without regard to the principles of conflicts of law. Under the terms of the Partnership Agreement, each partner and each person holding any beneficial interest in the Partnership agree that any claims arising under the Partnership Agreement or related to the Partnership shall be exclusively brought in the Court of Chancery of the State of Delaware, provided, however that any claims 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. The terms of the Partnership Agreement also provide that each partner irrevocably submits to the exclusive jurisdiction of the courts of the State of Delaware in connection with any claims pursuant to the Partnership Agreement.

Lack of Liquidity in Investment in Common Units

The common units will not be listed for trading or quotation on any securities exchange or other market, and you may have difficulty selling your common units. The common units are an illiquid investment, and purchasers should be able to hold their common units indefinitely.

Conditions to Becoming a Substitute Partner

An assignee of a common unit will not be entitled to any of the rights granted to a partner under the Partnership Agreement, other than the right to receive all or part of the share of the profits, losses, income, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled, unless the assignee becomes a substituted partner. In general, an assignee of a common unit will become a substitute limited partner upon acquisition of a common unit.

A substitute partner is entitled to all of the rights of full ownership of the assigned common units, including the right to vote.

8

EX-21.1

EXHIBIT 21.1

Subsidiaries of the Partnership

The following are wholly owned subsidiaries of Energy Resources 12, L.P.:

Energy Resources 12 Operating Company, LLC (Formed in Delaware)

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)

I, Glade M. Knight, certify that:

1. I have reviewed this Annual Report on Form 10-K of Energy Resources 12, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 17, 2021	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)

I, David S. McKenney, certify that:

1. I have reviewed this Annual Report on Form 10-K of Energy Resources 12, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 17, 2021	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Annual Report on Form 10-K (the “Form 10-K”) for the year ended December 31, 2020 of Energy Resources 12, L.P. (the “Partnership”). I, Glade M. Knight, the Chief Executive Officer of the Partnership, certify that, based on my knowledge:

(1)   The Form 10-K fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)   The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of and for the periods covered in this report.

Date:  March 17, 2021	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer (Principal Executive Officer)

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Partnership, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-32.2

EXHIBIT 32.2

CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Annual Report on Form 10-K (the “Form 10-K”) for the year ended December 31, 2020 of Energy Resources 12, L.P. (the “Partnership”). I, David S. McKenney, the Chief Financial Officer of the Partnership, certify that, based on my knowledge:

(1)   The Form 10-K fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)   The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of and for the periods covered in this report.

Date:  March 17, 2021	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Partnership, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-99.1

EXHIBIT 99.1

Energy Resources 12, L.P.

5815 N. Western Avenue

Oklahoma City, OK 73118

Reserves and Economic Evaluation

Year-End 2020 Reserves

Non-Operated Assets located within the

Williston Basin in North Dakota

Effective: January 1, 2021

SEC Pricing

Prepared: January 21, 2021

By: John Paul (J.P.) Dick, P.E.

Candace Cantrell, P.E.

January 21, 2021

Energy Resources 12, L.P.

5815 N. Western Avenue

Oklahoma City, OK 73118

Re:     Reserve & Economic Evaluation

Non-Operated Assets in the

Williston Basin, North Dakota

Year-End 2020 Reserves – SEC Price         

Executive Summary

An engineering and economic evaluation was prepared for oil and gas reserves located within the Williston Basin in North Dakota in which Energy Resources 12, L.P. (“ER12”) owns a working and/or royalty interest. The oil and gas reserves associated with these properties were evaluated and classified as Proved Reserves in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC). The Proved reserves include three hundred forty-eight (348) Proved Developed Producing (PDP) wells, thirty-six (36) Proved Developed Non-Producing (PDNP) wells; twenty-three (23) PaDNP wells are waiting on workover or offset activity to return to production and thirteen (13) PDNP wells have been commenced but are not yet on production; fifty (50) Proved Non-Consent (PNC) wells, (6) Proved Non-Consent Undeveloped (PNCUD) wells, and one hundred seventy-five (175) Proved Undeveloped (PUD) locations targeting the Bakken Shale and Three Forks formation in multiple sections/units. Also included in the attached economic reports are three (3) Proved Non-Consent Shut-In (PNCSI) wells; however, these wells were given no value or reserves for this evaluation. All wells and locations are horizontal.

Remaining reserves, future cashflow, and present worth values were calculated as of January 1, 2021. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by ER12.

The reserves and economics were determined using SEC YE2020 pricing as of January 1, 2021. Table 1 summarizes the estimated net reserves and future net revenue (cashflow), discounted and undiscounted, to the ER12 interest in these properties.

Table 1 - Net Reserve and Economic Report Summary
Reserve Category	#	Oil	Gas	NGL	Net Cashflow	PV 10%
	Wells	(Mbbl)	(MMcf)	(Mbbl)	($M)	($M)
Proved	623	17,066	16,979	2,225	193,421	68,013
PDP	349	6,616	8,819	1,180	99,172	50,112
PaDNP	23	249	372	28	3,770	1,784
PDNP	13	73	50	8	790	305
PNC	50	17	11	2	274	118
PNCSI	3	0	0	0	0	0
PNCUD	6	14	11	0	265	34
PUD	175	10,097	7,716	1,006	89,150	15,661
PA	4	0	0	0	0	0

Economic Evaluation

Future Income

Future net revenue in this report includes deductions for state production taxes. Future net cashflow is after deducting state production taxes, future capital investments, and lease operating expenses but before consideration of any state and/or federal income taxes. For purposes of this evaluation, future capital investments include costs for drilling, completing, and equipping new wells. Abandonment costs of 100 M$ at the end of well life for each well have been included in this evaluation. The future net cashflow has not been adjusted for any outstanding loans that may exist, cash on hand, or undistributed income. Future net cashflow has been discounted at an annual rate of ten percent (10%) to determine its “present worth.” The present worth is shown to indicate the effect of time on the value of money. Future net revenue (cashflow) presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties evaluated.

Interests

Well and leasehold interests were provided by ER12 and are shown by well in Exhibit A. The non-operated interests for all proved reserves average approximately 5.8% working interest and 4.6% net revenue interest.

Product Pricing

Per SEC rules, the SEC pricing is determined by calculating the unweighted arithmetic average of the first-day-of-the-month NYMEX oil and gas pricing for the prior twelve calendar months (January 2020 through December 2020) to the date of evaluation. All prices are held constant throughout the lives of the properties. For year-end 2020, the unweighted arithmetic average NYMEX (Cushing) oil price is 39.57 $/bbl and the average NYMEX (Henry Hub) natural gas price is 1.99 $/MMbtu. Prices were adjusted for quality, basis, energy content, transportation fees and other market differentials based on an analysis of revenue data.

Differentials to NYMEX pricing were calculated by examining revenue statements and financial information to determine deductions or increases to oil and gas prices due to Btu, differentials, NGLs, processing, transportation, and/or contract terms. The pricing adjustments and differentials are shown by well in Exhibit B.

Including the adjustments for quality, basis, energy content, transportation fees and other market differentials, the average realized price throughout the lives of the properties were 31.82 $/bbl oil, -2.32 $/Mcf natural gas and 3.12 $/bbl NGL.

Expenses

A variable expense of $8.50/bbl oil was provided by ER12 to model the well life expense changes for all wells and undeveloped locations, based on actual costs and the age of each individual well. Expenses were not escalated.

Future Well Investments

Capital expenses for the future locations were estimated by operator and are shown by well in Exhibit B. Capital timing for future development work was determined by operator and provided by ER12. Pinnacle cannot be responsible for capital costs that exceed or are less than these estimates.

Reserve Determination

Reserve Discussion

Remaining recoverable reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty depending primarily on the amount of reliable geologic and engineering (production, pressure) data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty is conveyed by classifying reserves as Proved (highly certain) or Non-Proved (less certain). The estimated reserves and revenues shown in this report were determined by SEC standards for Proved Developed Producing (PDP) wells, Proved Developed Non-Producing (PDNP) wells, Proved Non-Consent (PNC) wells, Proved Non-Consent Undeveloped (PNCUD), and Proved Undeveloped (PUD) locations.

Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs with defined limits and under current economic conditions, operating methods, and government regulations. Changes in any of these variables could materially change the reserves actually recovered.

Proved reserves are further classified as Proved Developed Producing (PDP) and Proved Non-Consent (PNC) which is assigned to wells with sufficient production history to allow material balance and decline curve analysis to be the primary methods of estimation. PDP and PNC reserves are the most reliable reserves, generally with a high degree of confidence (>90%) that actually recovered quantities will equal or exceed published reserve estimates.

Proved Developed Non-Producing (PDNP) reserves include zones that have been penetrated by drilling but have not produced or have not produced in sufficient quantities to allow material balance or decline curve analysis with a high degree of confidence. This category includes wells awaiting completion. Also included in this category are wells that have temporarily stopped producing due to offset activity or workover operations but will return to production as soon as work has been commenced.

Proved Undeveloped (PUD) and Proved Non-Consent Undeveloped (PNCUD) reserves are those quantities of petroleum that are estimated to be recovered from undrilled acreage (locations) in a continuous portion of the Proved Developed reservoir as defined by directly offsetting PDP wells and geological interpretations. The Proved Undeveloped and In Progress wells are forecasted based on geological data presented, volumetric calculations, and analog comparisons to existing completions.

General

The reserves and values included in this report are estimates only and should not be construed as being exact quantities. The reserve estimates were performed using accepted engineering practices and were primarily based on historical rate decline analysis for existing producers. When possible and practical, volumetric calculations and analogies were integrated into the reserve estimates. As additional pressure and production performance data becomes available, reserve estimates may increase or decrease in the future. The revenue from such reserves and the actual costs related may be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves included in this report and the costs incurred in recovering such reserves may vary from the price and cost assumptions referenced. Therefore, in all cases, estimates of reserves may increase or decrease as a result of future operations. We consider all assumptions, data, and procedures utilized in this report appropriate for the purpose of this report.

In evaluating the information available for this analysis, items excluded from consideration were all matters as to which legal or accounting interpretation, rather than engineering interpretation, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and such conclusions necessarily represent only informed professional judgments.

Pinnacle Energy Services, LLC is an established petroleum engineering consulting firm. We hereby confirm that neither this firm, its affiliates, nor any of its employees, members, officers, or directors has, or is committed to acquire any interest, directly or indirectly, in the properties covered by this report, in any partnership, any general partner of the partnerships, nor is this firm or any employee, member or officer, or director thereof otherwise affiliated with any partnership or any such general partner. This report was completely independently prepared by Pinnacle Energy Services, LLC and our engagement and payment for services in connection with this report is independent of the outcome and not on a contingent basis.

The titles to the properties have not been examined nor has the actual degree or type of interest owned been independently confirmed. A field inspection of the properties is not usually considered necessary for the purpose of this report.

All information reviewed and utilized will be retained and is available for review by authorized parties at any time. Information used to prepare the evaluation was provided by Energy Resources 12, L.P. and was supplemented by public and in-house data. Pinnacle Energy Services, LLC can take no responsibility for the accuracy of the data used in the analysis, whether gathered from public sources or otherwise.

Pinnacle Energy Services, LLC

/s/ J.P. Dick                                                John Paul (J.P.) Dick, P.E.   Petroleum Engineer  /s/ Candace Cantrell                                      Candace Cantrell, P.E.          Petroleum Engineer

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Mar. 17, 2021	Jun. 30, 2020
Document Information Line Items
Entity Registrant Name	Energy Resources 12, L.P.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		11,031,579
Entity Public Float			$ 0
Amendment Flag	false
Entity Central Index Key	0001696088
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Shell Company	false
Entity Ex Transition Period	true
Document Annual Report	true
Document Transition Report	false
Entity File Number	000-55916
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	81-4805237
Entity Address, Address Line One	120 W 3rd Street, Suite 220
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	882-9192
Title of 12(g) Security	Common Units of Limited Partnership Interest
Entity Interactive Data Current	Yes

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Assets
Cash and cash equivalents	$ 3,076,840	$ 14,834,452
Accounts receivable and other current assets	5,629,026	8,186,604
Total Current Assets	8,705,866	23,021,056
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $36,136,401 and $21,955,397, respectively	192,170,057	197,498,771
Total Assets	200,875,923	220,519,827
Liabilities
Accounts payable and accrued expenses	3,658,846	9,052,746
Derivative liability	594,632	207,327
Total Current Liabilities	4,253,478	9,260,073
Asset retirement obligations	624,089	570,795
Total Liabilities	4,877,567	9,830,868
Partners’ Equity
Limited partners' interest (11,031,579 common units issued and outstanding, respectively)	195,998,571	210,689,174
General partner's interest	(215)	(215)
Total Partners’ Equity	195,998,356	210,688,959
Total Liabilities and Partners’ Equity	$ 200,875,923	$ 220,519,827

XML

Consolidated Balance Sheets (Parentheticals) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Oil and natural gas properties, successful efforts method, accumulated depreciation, depletion and amortization (in Dollars)	$ 36,136,401	$ 21,955,397
Limited partners' interest, common units issued	11,031,579	11,031,579
Limited partners' interest, common units outstanding	11,031,579	11,031,579

XML

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues
Oil	$ 31,904,428	$ 61,146,651
Natural gas	1,732,123	2,005,423
Natural gas liquids	1,278,167	1,278,743
Total revenue	34,914,718	64,430,817
Operating costs and expenses
Production expenses	15,455,915	17,027,589
Production taxes	2,924,746	5,772,463
General and administrative expenses	2,377,005	2,323,230
Depreciation, depletion, amortization and accretion	14,204,418	17,203,330
Total operating costs and expenses	34,962,084	42,326,612
Operating income (loss)	(47,366)	22,104,205
Interest income (expense), net	29,859	(1,620,953)
Loss on extinguishment of debt	0	(999,172)
Gain (loss) on derivatives, net	728,808	(1,143,292)
Total other expense, net	758,667	(3,763,417)
Net income	$ 711,301	$ 18,340,788
Basic and diluted net income per common unit (in Dollars per share)	$ 0.06	$ 1.92
Weighted average common units outstanding - basic and diluted (in Shares)	11,031,579	9,555,311

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Consolidated Statements of Partners' Equity - USD ($)	Total	Limited Partner [Member]	General Partner [Member]
Balance at Dec. 31, 2018	$ 146,001,144	$ 146,001,359	$ (215)
Balance (in Shares) at Dec. 31, 2018		7,857,359
Net proceeds from issuance of common units	59,633,446	$ 59,633,446
Net proceeds from issuance of common units (in Shares)		3,174,220
Distributions declared and paid to common units	(13,286,419)	$ (13,286,419)
Net income	18,340,788	18,340,788
Balance at Dec. 31, 2019	$ 210,688,959	$ 210,689,174	(215)
Balance (in Shares) at Dec. 31, 2019	11,031,579	11,031,579
Distributions declared and paid to common units	$ (15,401,904)	$ (15,401,904)
Net income	711,301	711,301
Balance at Dec. 31, 2020	$ 195,998,356	$ 195,998,571	$ (215)
Balance (in Shares) at Dec. 31, 2020	11,031,579	11,031,579

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Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
General Partner [Member]
Distributions declared and paid per unit	$ 1.396165	$ 1.396164

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Consolidated Statement of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash flow from operating activities:
Net income	$ 711,301	$ 18,340,788
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	14,204,418	17,203,330
Loss on mark-to-market of derivatives	387,305	1,086,944
Loss on extinguishment of debt	0	999,172
Non-cash expenses, net		513,770
Changes in operating assets and liabilities:
Accounts receivable and other current assets	2,557,578	(4,755,540)
Accounts payable and accrued expenses	(1,540,250)	2,697,734
Net cash flow provided by operating activities	16,320,352	36,086,198
Cash flow from investing activities:
Cash paid for acquisition of oil and natural gas properties	(110,073)	(1,367,256)
Additions to oil and natural gas properties	(12,565,987)	(36,408,112)
Net cash flow used in investing activities	(12,676,060)	(37,775,368)
Cash flow from financing activities:
Net proceeds from (payments on) revolving credit facility	0	(39,500,000)
Net proceeds related to issuance of common units	0	59,627,639
Distributions paid to limited partners	(15,401,904)	(13,286,419)
Net cash flow provided by (used in) financing activities	(15,401,904)	6,841,220
Increase (decrease) in cash and cash equivalents	(11,757,612)	5,152,050
Cash and cash equivalents, beginning of period	14,834,452	9,682,402
Cash and cash equivalents, end of period	3,076,840	14,834,452
Interest paid	0	1,170,811
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$ 2,095,846	$ 6,048,081

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Partnership Organization

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Note 1.  Partnership Organization

Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. The proceeds from the sale of the common units have been used to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties.

As of December 31, 2020, the Partnership owned an approximate 5.8% non-operated working interest in 372 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Partnership also owns an estimated approximate 1% non-operated working interest in 13 wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners.

The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership.

The Partnership’s fiscal year ends on December 31. 

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Note 2.  Summary of Significant Accounting Policies

Basis of Presentation

The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).

Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

Property and Depreciation, Depletion and Amortization

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Partnership’s accounts receivable are due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2020 and 2019, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible and the Partnership’s operators do not have a history of non-payment. For the years ended December 31, 2020 and 2019, the Partnership’s oil, natural gas and NGL sales were through 14 operators and approximately 92% and 91% of the Partnership’s total revenue was generated through sales by four operators, respectively. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

Accounting for Asset Retirement Obligations

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

The following table shows the activity for the years ended December 31, 2020 and 2019 relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2018	$	383,255
Well additions		49,801
Accretion		20,607
Revisions (1)		117,132
Balance as of December 31, 2019		570,795
Well additions		29,880
Accretion		23,414
Revisions		-
Balance as of December 31, 2020	$	624,089

(1) During 2019, six wells owned by the Partnership were deemed to be shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells.

Environmental Costs

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2020 and 2019, there were no such costs accrued.

Use of Estimates

The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable and other current assets in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership 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. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. 

Reclassifications

Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Net Income per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 7) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

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Oil and Gas Investments

12 Months Ended

Dec. 31, 2020

Oil and Gas Property [Abstract]

Oil and Gas Properties [Text Block]

Note 3.  Oil and Gas Investments

On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $90.5 million, including all closing costs and assumed liabilities. On August 31, 2018, the Partnership completed its second purchase of an additional non-operated working interest in the Bakken Assets for approximately $81.3 million, including all closing costs and assumed liabilities. As of December 31, 2020, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.8% non-operated working interest in 372 producing wells, and an estimated approximate 1% non-operated working interest in 13 wells in various stages of the drilling and completion process.

From September 1, 2017, the effective date of Acquisition No. 1, to December 31, 2020, the Partnership has participated in the drilling of 180 wells, of which 167 have been completed and 13 wells are in various stages of completion at December 31, 2020. The Partnership incurred approximately $8.8 million and $32.2 million in capital drilling and completion costs for the years ended December 31, 2020 and 2019, respectively. The Partnership anticipates approximately $0.4 million of capital expenditures to be incurred in first half of 2021 to complete the 13 wells in various stages of completion at December 31, 2020; however, actual capital expenditures incurred may exceed this range.

Evaluation for Potential Impairment of Oil and Natural Gas Investments

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Bakken Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of January 1, 2021, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Bakken Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of December 31, 2020.

If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.

Non-consent wells

Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute.

Through its 2018 acquisitions, the Partnership acquired 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.

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Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Note 4. Debt

On August 31, 2018, the Partnership entered into a loan agreement (“Loan Agreement”) with Simmons Bank, as administrative agent and the lenders party thereto, which provided for a revolving credit facility (“Credit Facility”) with an initial commitment amount of $60 million. The Credit Facility proceeds of $60.0 million borrowed at closing were used to fund the purchase of Acquisition No. 2, as described above, and pay closing costs. On November 26, 2019, the Partnership elected to terminate the Loan Agreement, which extinguished the Credit Facility and terminated the related mortgage secured by the Partnership’s non-operating working interests in the Bakken Assets. At the date of termination, the Partnership had no outstanding borrowings on the Loan Agreement. Early termination of the Loan Agreement did not require payment of any early termination penalties.

In conjunction with Acquisition No. 2 and the closing on the Loan Agreement, the Partnership capitalized $1.7 million of deferred loan costs, and the Partnership was amortizing these loan costs over the life of the Credit Facility to its maturity date of August 31, 2021. In November 2019, upon the termination of the Credit Facility, the Partnership expensed the remaining unamortized deferred loan costs and recorded a Loss on extinguishment of debt of $1.0 million on the Partnership’s consolidated statement of operations.

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Note 5. Fair Value of Financial Instruments

The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:

● Level 1: Quoted prices in active markets for identical assets

● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

● Level 3: Significant unobservable inputs

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the years ended December 31, 2020 and 2019, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019.

	Year Ended December 31, 2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(594,632	)	$	-
Total	$	-	$	(594,632	)	$	-

	Year Ended December 31, 2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(207,327	)	$	-
Total	$	-	$	(207,327	)	$	-

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheets as Derivative liability at December 31, 2020 and 2019. See additional detail in Note 6. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s cash and cash equivalents, accounts receivable and other current assets, accounts payable and accrued expenses reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

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Risk Management

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Note 6. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and the Partnership’s future earnings are subject to these risks. Therefore, the Partnership periodically enters into derivative contracts to manage the commodity price risk on a portion of the Partnership’s anticipated future oil and gas production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.

As of December 31, 2020 and 2019, the Partnership’s derivative instruments were in a loss position; therefore, current liabilities of approximately $0.6 million and $0.2 million, respectively, which approximate fair value, were recognized in Derivative Liability on the Partnership’s consolidated balance sheets.

The Partnership determined the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 5. Fair Value of Financial Instruments.

The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect a realized net gain on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) losses below represent the change in fair value of derivative instruments which were held at period-end.

	Year Ended December 31, 2020			Year Ended December 31, 2019
Settlements on matured derivatives, net	$	1,116,113		$	(56,348	)
Loss on mark-to-market of derivatives, net		(387,305	)		(1,086,944	)
Gain (loss) on derivatives, net	$	728,808		$	(1,143,292	)

The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of December 31, 2020.

Settlement Period	Basis	Oil (Barrels)		Floor / Ceiling Prices ($)	Fair Value of Liability at December 31, 2020
01/01/21 - 05/31/21	NYMEX		68,247	38.00 / 44.85	$	(324,723	)
01/01/21 - 05/31/21	NYMEX		68,247	37.50 / 46.00		(269,909	)
					$	(594,632	)

The Partnership’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.

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Capital Contribution and Partners' Equity

12 Months Ended

Dec. 31, 2020

Partners' Capital Notes [Abstract]

Partners' Capital Notes Disclosure [Text Block]

Note 7.  Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below) and has been and will be reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

The Partnership completed its best-efforts offering of common units as of the close of business on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

Under the agreement with David Lerner Associates, Inc. (the “Managing Dealer”), the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering on October 24, 2019, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).

Prior to “Payout,” which is defined below, all distributions made by the Partnership, if any, will be paid to the holders of common units.  Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs.

The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

For the year ended December 31, 2020, the Partnership paid distributions of $1.396165 per common unit, or $15.4 million. For the year ended December 31, 2019, the Partnership paid distributions of $1.396164 per common unit, or $13.3 million.

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Related Parties

12 Months Ended

Dec. 31, 2020

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

Note 8.  Related Parties

The Class A voting members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and David S. McKenney, Chief Financial Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. The Class B non-voting members of the General Partner are affiliates of Anthony F. Keating, III and Michael J. Mallick, the Co-Chief Operating Officers of Energy 11’s general partner.

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.

The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include costs for organizing the Partnership, costs incurred in the offering of the common units and general and administrative costs. The Partnership has also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the limited partner agreement, subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. The management fee paid to the General Partner for the years ended December 31, 2020 and 2019 was approximately $1.1 million and $1.0 million, respectively. The management fee paid to the General Partner is included in General and administrative expenses on the consolidated statements of operations.

For the years ended December 31, 2020 and 2019, approximately $380,000 and $414,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership, respectively. At December 31, 2020 and 2019, approximately $90,000 and $133,000, respectively, was due to a member of the General Partner and is included in Accounts payable and accrued expenses in the consolidated balance sheets.

On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 that gave the Partnership access to Energy 11’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs were split evenly between the two partnerships. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. Any other direct third-party costs were paid by the party receiving the services. The compensation due to the President of Energy 11’s general partner was also a shared cost between the Partnership and Energy 11 for the years ended December 31, 2020 and 2019. The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner; because the office space is shared between the Partnership and Energy 11, the monthly payments of $8,537 made in 2019 and 2020 were evenly split between the two partnerships in accordance with the cost sharing agreement. For the years ended December 31, 2020 and 2019, approximately $268,000 and $285,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and have been reimbursed to Energy 11. At December 31, 2019, approximately $85,000 was due from the Partnership to Energy 11 and is included in Accounts payable and accrued expenses in the consolidated balance sheet. In October 2020, the cost sharing agreement was terminated by the Partnership, effective December 31, 2020.

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and Energy 11, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. As described above, the Partnership currently pays the General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. Under the ASA, the General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. The General Partner has also agreed to pay the president of Energy 11’s general partner, who is an employee of the Administrator, an annual base compensation of $175,000, plus benefits, for his services that are included under the ASA.

The ASA is effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or Energy 11 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

12 Months Ended

Dec. 31, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

Note 9. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)

Aggregate Capitalized Costs and Costs Incurred

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2020 and 2019 is as follows:

	2020			2019
Producing properties	$	157,212,668		$	148,370,378
Non-producing		71,093,790			71,083,790
		228,306,458			219,454,168
Accumulated depreciation, depletion and amortization		(36,136,401	)		(21,955,397	)
Net capitalized costs	$	192,170,057		$	197,498,771

For the years ended December 31, 2020 and 2019, the Partnership incurred the following costs in oil and natural gas producing activities:

	2020		2019
Property acquisition costs	$	-	$	256,536
Development costs		8,852,290		32,229,159
	$	8,852,290	$	32,485,695

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences 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 renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 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. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2020, 2019 and 2018.

The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2020, 2019 and 2018 have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with SEC rules and regulations along with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history.

The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows:

	Proved Reserves
	Oil			Natural Gas			NGLs
	(Bbls)			(Mcf)			(Bbls)			Total (BOE)
December 31, 2018		20,264,440			9,962,790			1,492,085			23,416,990
Acquisition		-			-			-			-
Extensions, discoveries and other additions (1)		94,703			50,978			7,664			110,863
Revisions of previous estimates (2)		(1,047,353	)		(395,183	)		50,422			(1,062,795	)
Production		(1,129,951	)		(849,047	)		(126,760	)		(1,398,219	)
December 31, 2019		18,181,839			8,769,538			1,423,411			21,066,839
Acquisition		-			-			-			-
Extensions, discoveries and other additions (3)		954,587			668,211			122,579			1,188,535
Revisions of previous estimates (4)		(1,217,253	)		8,465,491			820,183			1,013,845
Production		(853,633	)		(924,481	)		(141,483	)		(1,149,197	)
December 31, 2020		17,065,540			16,978,759			2,224,690			22,120,022

(1)	In 2019, extensions, discoveries and other additions of 111 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(2)	Revisions to previous estimates decreased proved reserves by 1,063 MBOE. These revisions result from 804 MBOE of downward adjustments attributable to well performance, 246 MBOE of downward adjustments attributable to changes in the future drill schedule and 13 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.
(3)	In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(4)	Revisions to previous estimates increased proved reserves by 1,014 MBOE. The impact of these revisions had differing impacts to the Partnership’s oil, natural gas and NGL volumes. The revisions for oil volumes include 735 MBOE of downward adjustments attributable to well performance, 448 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019. The revisions for natural gas and NGL volumes include 1,800 MBOE of upward adjustments attributable to well performance, 443 MBOE of upward adjustments attributable to changes in the future drill schedule, and 11 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019.

In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2020 were $39.57 per barrel of oil and $1.99 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2020 were $31.82 per barrel of oil, $(2.33) per MMcf of natural gas and $3.13 per barrel of NGL. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2019 were $55.69 per barrel of oil and $2.58 per MMcf of natural gas, before price differentials. Including the effect of average price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2019 were $49.42 per barrel of oil, $(1.61) per MMcf of natural gas and $2.74 per barrel of NGL.

Net quantities of proved developed and proved undeveloped reserves at December 31, 2020, 2019 and 2018 are summarized in the table below.

	Oil		Natural Gas		NGLs
	(Bbls)		(Mcf)		(Bbls)		Total (BOE)
Proved developed reserves:
December 31, 2018		6,982,216		4,126,780		686,765		8,356,778
December 31, 2019		6,986,035		4,733,090		774,311		8,549,194
December 31, 2020		6,881,782		9,202,098		1,210,323		9,625,787
Proved undeveloped reserves:
December 31, 2018		13,282,224		5,836,010		805,320		15,060,212
December 31, 2019		11,195,804		4,036,448		649,100		12,517,645
December 31, 2020		10,183,758		7,776,661		1,014,367		12,494,235

The following details the changes in proved undeveloped reserves (PUD) for 2019 and 2020 (in BOE):

	BOE
Proved undeveloped reserves, December 31, 2018		15,060,212
Revisions of previous estimates (1)		(401,688	)
Extensions, discoveries and other additions (2)		52,367
Conversion to proved developed reserves (3)		(2,193,246	)
Proved undeveloped reserves, December 31, 2019		12,517,645
Revisions of previous estimates (4)		697,585
Extensions, discoveries and other additions (5)		1,188,535
Conversion to proved developed reserves (6)		(1,909,530	)
Proved undeveloped reserves, December 31, 2020		12,494,235

(1)	The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019, and 9 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.
(2)	In 2019, extensions, discoveries and other additions of 52 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(3)	The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE.
(4)	The annual review of the PUDs resulted in a positive revision of approximately 698 MBOE. This revision was the result of 724 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2019, 21 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, and 5 MBOE of downward adjustments attributable to changes in the future drill schedule.
(5)	In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(6)	The Partnership converted 34 wells to proved developed reserves during 2020 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 1,909 MBOE.

The Partnership anticipates all current PUD locations will be drilled and converted to PDP within five years of the date they were added. PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves have been removed as revisions at the time that determination was made.

Standardized Measure of Discounted Future Net Cash Flows

Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2020			2019
	(in thousands)			(in thousands)
Future cash inflows	$	510,534		$	888,271
Future production costs		(233,563	)		(244,165	)
Future development costs		(83,551	)		(88,056	)
Future net cash flows		193,420			556,050
10% annual discount		(125,407	)		(312,901	)
Standardized measure of discounted future net cash flows	$	68,013		$	243,149

Changes in the standardized measure of discounted future net cash flows are as follows:

	2020			2019
	(in thousands)			(in thousands)
Standardized measure at beginning of period	$	243,149		$	370,495
Changes resulting from:
Acquisition of reserves		-			-
Extensions, discoveries and other additions		7,889			1,093
Sales of oil, natural gas and NGLs, net of production costs		(16,534	)		(41,631	)
Net changes in prices and production costs		(149,606	)		(97,776	)
Development costs incurred during the period		8,852			32,229
Revisions to previous estimates		(45,739	)		(40,287	)
Accretion of discount		24,349			37,101
Change in estimated future development costs		(4,347	)		(18,075	)
Standardized measure of discounted future net cash flows	$	68,013		$	243,149

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

Note 10.  Quarterly Financial Data (Unaudited)

The following is a summary of quarterly results of operations for the years ended December 31, 2020 and 2019. Net income per common unit is non-additive in comparison to net income per common unit for each year due to the timing and size of the Partnership’s common unit issuances.

	2020
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
Total revenue	$	11,932,896		3,189,431			7,903,439			11,888,952
Net income (loss)	$	2,214,315		(2,824,856	)		(76,659	)		1,398,501
Basic and diluted net income (loss) per common share	$	0.20		(0.26	)		(0.01	)		0.13

	2019
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Total revenue	$	11,361,830	$	18,832,114	$	15,883,884	$	18,352,989
Net income	$	1,641,943	$	8,277,089	$	5,680,657	$	2,741,099
Basic and diluted net income per common share	$	0.20	$	0.92	$	0.56	$	0.25

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Subsequent Events

12 Months Ended

Dec. 31, 2020

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 11.  Subsequent Events

In January 2021, the Partnership declared and paid $1.5 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units.

In February 2021, the Partnership declared and paid $1.2 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

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Accounting Policies, by Policy (Policies)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

Oil and Gas Properties Policy [Policy Text Block]

Property and Depreciation, Depletion and Amortization

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions

Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]

Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Concentration Risk, Credit Risk, Policy [Policy Text Block]

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Partnership’s accounts receivable are due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2020 and 2019, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible and the Partnership’s operators do not have a history of non-payment. For the years ended December 31, 2020 and 2019, the Partnership’s oil, natural gas and NGL sales were through 14 operators and approximately 92% and 91% of the Partnership’s total revenue was generated through sales by four operators, respectively. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership

Asset Retirement Obligation [Policy Text Block]

Accounting for Asset Retirement Obligations

The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

The following table shows the activity for the years ended December 31, 2020 and 2019 relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2018	$	383,255
Well additions		49,801
Accretion		20,607
Revisions (1)		117,132
Balance as of December 31, 2019		570,795
Well additions		29,880
Accretion		23,414
Revisions		-
Balance as of December 31, 2020	$	624,089

(1) During 2019, six wells owned by the Partnership were deemed to be shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells.

Environmental Costs, Policy [Policy Text Block]

Environmental Costs

As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved.

Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2020 and 2019, there were no such costs accrued.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions.

The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.

Revenue [Policy Text Block]

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable and other current assets in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership 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. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. 

Reclassification, Comparability Adjustment [Policy Text Block]

Reclassifications

Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.

Income Tax, Policy [Policy Text Block]

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Earnings Per Share, Policy [Policy Text Block]

Net Income per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 7) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

The following table shows the activity for the years ended December 31, 2020 and 2019 relating to the Partnership’s asset retirement obligations:

Balance as of December 31, 2018	$	383,255
Well additions		49,801
Accretion		20,607
Revisions (1)		117,132
Balance as of December 31, 2019		570,795
Well additions		29,880
Accretion		23,414
Revisions		-
Balance as of December 31, 2020	$	624,089

(1) During 2019, six wells owned by the Partnership were deemed to be shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells.

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019.

	Year Ended December 31, 2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(594,632	)	$	-
Total	$	-	$	(594,632	)	$	-

	Year Ended December 31, 2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(207,327	)	$	-
Total	$	-	$	(207,327	)	$	-

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Risk Management (Tables)

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments, Gain (Loss) [Table Text Block]

The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect a realized net gain on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) losses below represent the change in fair value of derivative instruments which were held at period-end.

	Year Ended December 31, 2020			Year Ended December 31, 2019
Settlements on matured derivatives, net	$	1,116,113		$	(56,348	)
Loss on mark-to-market of derivatives, net		(387,305	)		(1,086,944	)
Gain (loss) on derivatives, net	$	728,808		$	(1,143,292	)

Schedule of Derivative Instruments [Table Text Block]

The following table reflects the open costless collar derivative instruments as of December 31, 2020.

Settlement Period	Basis	Oil (Barrels)		Floor / Ceiling Prices ($)	Fair Value of Liability at December 31, 2020
01/01/21 - 05/31/21	NYMEX		68,247	38.00 / 44.85	$	(324,723	)
01/01/21 - 05/31/21	NYMEX		68,247	37.50 / 46.00		(269,909	)
					$	(594,632	)

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2020 and 2019 is as follows:

	2020			2019
Producing properties	$	157,212,668		$	148,370,378
Non-producing		71,093,790			71,083,790
		228,306,458			219,454,168
Accumulated depreciation, depletion and amortization		(36,136,401	)		(21,955,397	)
Net capitalized costs	$	192,170,057		$	197,498,771

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

For the years ended December 31, 2020 and 2019, the Partnership incurred the following costs in oil and natural gas producing activities:

	2020		2019
Property acquisition costs	$	-	$	256,536
Development costs		8,852,290		32,229,159
	$	8,852,290	$	32,485,695

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows:

	Proved Reserves
	Oil			Natural Gas			NGLs
	(Bbls)			(Mcf)			(Bbls)			Total (BOE)
December 31, 2018		20,264,440			9,962,790			1,492,085			23,416,990
Acquisition		-			-			-			-
Extensions, discoveries and other additions (1)		94,703			50,978			7,664			110,863
Revisions of previous estimates (2)		(1,047,353	)		(395,183	)		50,422			(1,062,795	)
Production		(1,129,951	)		(849,047	)		(126,760	)		(1,398,219	)
December 31, 2019		18,181,839			8,769,538			1,423,411			21,066,839
Acquisition		-			-			-			-
Extensions, discoveries and other additions (3)		954,587			668,211			122,579			1,188,535
Revisions of previous estimates (4)		(1,217,253	)		8,465,491			820,183			1,013,845
Production		(853,633	)		(924,481	)		(141,483	)		(1,149,197	)
December 31, 2020		17,065,540			16,978,759			2,224,690			22,120,022

(1)	In 2019, extensions, discoveries and other additions of 111 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(2)	Revisions to previous estimates decreased proved reserves by 1,063 MBOE. These revisions result from 804 MBOE of downward adjustments attributable to well performance, 246 MBOE of downward adjustments attributable to changes in the future drill schedule and 13 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.
(3)	In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(4)	Revisions to previous estimates increased proved reserves by 1,014 MBOE. The impact of these revisions had differing impacts to the Partnership’s oil, natural gas and NGL volumes. The revisions for oil volumes include 735 MBOE of downward adjustments attributable to well performance, 448 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019. The revisions for natural gas and NGL volumes include 1,800 MBOE of upward adjustments attributable to well performance, 443 MBOE of upward adjustments attributable to changes in the future drill schedule, and 11 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019.

	Oil		Natural Gas		NGLs
	(Bbls)		(Mcf)		(Bbls)		Total (BOE)
Proved developed reserves:
December 31, 2018		6,982,216		4,126,780		686,765		8,356,778
December 31, 2019		6,986,035		4,733,090		774,311		8,549,194
December 31, 2020		6,881,782		9,202,098		1,210,323		9,625,787
Proved undeveloped reserves:
December 31, 2018		13,282,224		5,836,010		805,320		15,060,212
December 31, 2019		11,195,804		4,036,448		649,100		12,517,645
December 31, 2020		10,183,758		7,776,661		1,014,367		12,494,235

	BOE
Proved undeveloped reserves, December 31, 2018		15,060,212
Revisions of previous estimates (1)		(401,688	)
Extensions, discoveries and other additions (2)		52,367
Conversion to proved developed reserves (3)		(2,193,246	)
Proved undeveloped reserves, December 31, 2019		12,517,645
Revisions of previous estimates (4)		697,585
Extensions, discoveries and other additions (5)		1,188,535
Conversion to proved developed reserves (6)		(1,909,530	)
Proved undeveloped reserves, December 31, 2020		12,494,235

(1)	The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019, and 9 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.
(2)	In 2019, extensions, discoveries and other additions of 52 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(3)	The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE.
(4)	The annual review of the PUDs resulted in a positive revision of approximately 698 MBOE. This revision was the result of 724 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2019, 21 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, and 5 MBOE of downward adjustments attributable to changes in the future drill schedule.
(5)	In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
(6)	The Partnership converted 34 wells to proved developed reserves during 2020 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 1,909 MBOE.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2020			2019
	(in thousands)			(in thousands)
Future cash inflows	$	510,534		$	888,271
Future production costs		(233,563	)		(244,165	)
Future development costs		(83,551	)		(88,056	)
Future net cash flows		193,420			556,050
10% annual discount		(125,407	)		(312,901	)
Standardized measure of discounted future net cash flows	$	68,013		$	243,149

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

Changes in the standardized measure of discounted future net cash flows are as follows:

	2020			2019
	(in thousands)			(in thousands)
Standardized measure at beginning of period	$	243,149		$	370,495
Changes resulting from:
Acquisition of reserves		-			-
Extensions, discoveries and other additions		7,889			1,093
Sales of oil, natural gas and NGLs, net of production costs		(16,534	)		(41,631	)
Net changes in prices and production costs		(149,606	)		(97,776	)
Development costs incurred during the period		8,852			32,229
Revisions to previous estimates		(45,739	)		(40,287	)
Accretion of discount		24,349			37,101
Change in estimated future development costs		(4,347	)		(18,075	)
Standardized measure of discounted future net cash flows	$	68,013		$	243,149

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Table Text Block]

The following is a summary of quarterly results of operations for the years ended December 31, 2020 and 2019. Net income per common unit is non-additive in comparison to net income per common unit for each year due to the timing and size of the Partnership’s common unit issuances.

	2020
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
Total revenue	$	11,932,896		3,189,431			7,903,439			11,888,952
Net income (loss)	$	2,214,315		(2,824,856	)		(76,659	)		1,398,501
Basic and diluted net income (loss) per common share	$	0.20		(0.26	)		(0.01	)		0.13

	2019
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Total revenue	$	11,361,830	$	18,832,114	$	15,883,884	$	18,352,989
Net income	$	1,641,943	$	8,277,089	$	5,680,657	$	2,741,099
Basic and diluted net income per common share	$	0.20	$	0.92	$	0.56	$	0.25

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Partnership Organization (Details) shares in Millions		12 Months Ended		25 Months Ended
	Dec. 30, 2016 USD ($)	Dec. 31, 2020	Dec. 31, 2019 USD ($)	Oct. 24, 2019 USD ($) shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State	Delaware
Partners' Capital Account, Contributions (in Dollars)	$ 1,000
Proceeds from Issuance of Common Limited Partners Units (in Dollars)			$ 59,633,446
Bakken Assets [Member]
Partnership Organization (Details) [Line Items]
Number of Operators		14
Bakken Assets [Member] | Non-operated Completed Wells [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		5.80%
Oil, Productive Well, Number of Wells, Net		372
Bakken Assets [Member] | Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		1.00%
Oil and Gas, Present Activity, Well in Process of Drilling		13
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares				11.0
Proceeds from Issuance of Common Limited Partners Units (in Dollars)				$ 218,000,000.0
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)				$ 204,300,000

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Summary of Significant Accounting Policies (Details) [Line Items]
Number of Wells shut-in		6
Revenue Benchmark [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Number of Operators	14
Customer Concentration Risk [Member] | Four Operators [Member] | Revenue Benchmark [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Number of Operators	4	4
Concentration Risk, Percentage	92.00%	91.00%

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Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Asset Retirement Obligations [Abstract]
Balance	$ 570,795	$ 383,255
Well additions	29,880	49,801
Accretion	23,414	20,607
Revisions	0	117,132	[1]
Balance	$ 624,089	$ 570,795

[1] During 2019, six wells owned by the Partnership were deemed to be shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells.

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Oil and Gas Investments (Details)			12 Months Ended			40 Months Ended
	Aug. 31, 2018 USD ($)	Feb. 01, 2018 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018	Dec. 31, 2020
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number			34	38
Costs Incurred, Development Costs (in Dollars)			$ 8,852,290	$ 32,229,159
Non-consent well description					Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute. Through its 2018 acquisitions, the Partnership acquired 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.
Number of Wells Designated as Non-Consent Wells					59
Minimum [Member]
Oil and Gas Investments (Details) [Line Items]
Non-consent penalty range					200.00%
Maximum [Member]
Oil and Gas Investments (Details) [Line Items]
Non-consent penalty range					400.00%
Non-operated Completed Wells [Member] | Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			5.80%
Oil, Productive Well, Number of Wells, Net			372			372
Non-operated Wells in the Process of Drilling [Member] | Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			1.00%
Oil, Productive Well, Number of Wells, Net			13			13
Acquisition No. 1 [Member] | Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)		$ 90,500,000
Wells Drilled						180
Oil and Gas, Development Well Drilled, Net Productive, Number						167
Oil and Gas, Present Activity, Well in Process of Drilling			13			13
Costs Incurred, Development Costs (in Dollars)			$ 8,800,000	$ 32,200,000
Capital Expenditures Drilling and Completion of Wells (in Dollars)			$ 400,000
Acquisition No. 2 [Member] | Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)	$ 81,300,000

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Debt (Details) - USD ($)		12 Months Ended
	Aug. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Nov. 26, 2019
Debt (Details) [Line Items]
Gain (Loss) on Extinguishment of Debt		$ 0	$ (999,172)
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000
Long-term Line of Credit				$ 0
Deferred Costs	$ 1,700,000
Debt Instrument, Maturity Date	Aug. 31, 2021

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Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	$ 0	$ 0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	(594,632)	(207,327)
Total	(594,632)	(207,327)
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	0	0
Total	$ 0	$ 0

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Risk Management (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Liability, Current	$ 594,632	$ 207,327

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Risk Management (Details) - Derivative Instruments, Gain (Loss) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Abstract]
Settlements on matured derivatives, net	$ 1,116,113	$ (56,348)
Loss on mark-to-market of derivatives, net	(387,305)	(1,086,944)
Gain (loss) on derivatives, net	$ 728,808	$ (1,143,292)

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Risk Management (Details) - Schedule of Derivative Instruments	12 Months Ended
	Dec. 31, 2020 USD ($) $ / item bbl
Derivative [Line Items]
Fair Value of Liability (in Dollars) | $	$ (594,632)
Costless Collar Agreements #1 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	68,247
Floor Price	38.00
Fair Value of Liability (in Dollars) | $	$ (324,723)
Ceiling Price	44.85
Costless Collar Agreements #2 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	68,247
Floor Price	37.50
Fair Value of Liability (in Dollars) | $	$ (269,909)
Ceiling Price	46.00

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Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions		12 Months Ended			25 Months Ended
	Dec. 30, 2016	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2017	Oct. 24, 2019
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Partners' Capital Account, Return of Contribution Upon Minimum Offering				$ 990
Proceeds from Issuance of Common Limited Partners Units			$ 59,633,446
Partners' Capital Account, Description of Units Sold		Under the agreement with David Lerner Associates, Inc. (the “Managing Dealer”), the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership.
Managing Dealer, Selling Commissions, Percentage		6.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage		4.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds		$ 8,700,000
Key Provisions of Operating or Partnership Agreement, Description		The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:    ● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.     ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.  All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)		$ 1.396165	$ 1.396164
Distribution Made to Limited Partner, Cash Distributions Paid		$ 15,401,904	$ 13,286,419
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)					11.0
Proceeds from Issuance of Common Limited Partners Units					$ 218,000,000.0
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units					$ 204,300,000

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Related Parties (Details) - USD ($)		12 Months Ended
	Dec. 01, 2020	Dec. 31, 2020	Dec. 31, 2019
Related Parties (Details) [Line Items]
Related Party Transaction, Description of Transaction		subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering.
General Partner [Member]
Related Parties (Details) [Line Items]
Due to Related Parties, Current		$ 90,000	$ 133,000
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		380,000	414,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals		8,537
Energy 11 [Member]
Related Parties (Details) [Line Items]
Due to Related Parties, Current			85,000
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		268,000	285,000
Related Party, Administrative Service Agreement	the Partnership currently pays the General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. Under the ASA, the General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA
Salary and Wage, Officer, Excluding Cost of Good and Service Sold	$ 175,000
Management Fee [Member] | General Partner [Member]
Related Parties (Details) [Line Items]
Due to Related Parties, Current		$ 1,100,000	$ 1,000,000.0

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2020 Boe		Dec. 31, 2020 mJ	Dec. 31, 2020 $ / bbl	Dec. 31, 2020 $ / Mcf	Dec. 31, 2019 Boe $ / bbl $ / Mcf		Dec. 31, 2018 Boe	[2]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		697,585	[1]						(401,688)
Oil and Gas, Development Well Drilled, Net Productive, Number	34						38
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)		(1,909,530)	[3]				(2,193,246)	[4]
Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(1,014,000)					(1,063,000)
Proved Reserves [Member] | Adjustments Related to Well Performance [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(735,000)		1,800			804,000
Proved Reserves [Member] | Adjustments Related to Changes in Future Drill Schedule [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(448,000)		443			246,000
Proved Reserves [Member] | Adjustments Related to Prices [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(35,000)		11			13,000
Proved Reserves [Member] | Adjustments Related to Successful Drilling [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)							52,000
Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(698,000)					(402,000)
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)		(1,909,000)
Proved Undeveloped Reserves [Member] | Adjustments Related to Changes in Future Drill Schedule [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		5,000
Proved Undeveloped Reserves [Member] | Adjustments Related to Prices [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(21,000)					(9,000)
Proved Undeveloped Reserves [Member] | Changes in Natural Gas Shrink [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(724,000)					(147,000)
Measurement Input, Discount Rate [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Future Cash Flows Measurement Input	10.00%						10.00%
Before Price Differentials [Member] | Oil [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl					39.57		55.69
Before Price Differentials [Member] | Natural Gas [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / Mcf						1.99	2.58
Including Effects of Price Differential Adjustments [Member] | Oil [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl					31.82		49.42
Including Effects of Price Differential Adjustments [Member] | Natural Gas [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / Mcf						(2.33)	(1.61)
Including Effects of Price Differential Adjustments [Member] | Natural Gas Liquids [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl					3.13		2.74
Acquisition No. 1 [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)		1,189,000					111,000

[1] The annual review of the PUDs resulted in a positive revision of approximately 698 MBOE. This revision was the result of 724 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2019, 21 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, and 5 MBOE of downward adjustments attributable to changes in the future drill schedule.

[2] The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019, and 9 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.

[3] The Partnership converted 34 wells to proved developed reserves during 2020 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 1,909 MBOE.

[4] The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE.

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
	$ 228,306,458	$ 219,454,168
Accumulated depreciation, depletion and amortization	(36,136,401)	(21,955,397)
Net capitalized costs	192,170,057	197,498,771
Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved Properties	157,212,668	148,370,378
Non-Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved Properties	$ 71,093,790	$ 71,083,790

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Property acquisition costs	$ 0	$ 256,536
Development costs	8,852,290	32,229,159
	$ 8,852,290	$ 32,485,695

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2020 Boe bbl Mcf		Dec. 31, 2019 Boe bbl Mcf		Dec. 31, 2018 Boe bbl Mcf
Reserve Quantities [Line Items]
Balance	21,066,839		23,416,990
Balance proved developed reserves (in Barrels of Oil Equivalent) | Boe	9,625,787		8,549,194		8,356,778
Balance proved undeveloped reserves (in Barrels of Oil Equivalent) | Boe	12,494,235		12,517,645		15,060,212
Balance proved undeveloped reserves (in Barrels of Oil Equivalent) | Boe	12,494,235		12,517,645		15,060,212
Revisions of previous estimates (in Barrels of Oil Equivalent) | Boe	697,585	[1]			(401,688)	[2]
Extensions, discoveries and other additions (in Barrels of Oil Equivalent) | Boe	1,188,535	[3]	52,367	[4]
Conversion to proved developed reserves (in Barrels of Oil Equivalent) | Boe	(1,909,530)	[5]	(2,193,246)	[6]
Acquisition	0
Extensions, discoveries and other additions	1,188,535	[3]	110,863	[7]
Revisions of previous estimates	1,013,845	[8]	(1,062,795)	[9]
Production	(1,149,197)		(1,398,219)
Balance	22,120,022		21,066,839		23,416,990
Oil [Member]
Reserve Quantities [Line Items]
Balance	18,181,839		20,264,440
Balance proved developed reserves	6,881,782		6,986,035		6,982,216
Balance proved undeveloped reserves	10,183,758		11,195,804		13,282,224
Acquisition	0
Extensions, discoveries and other additions	954,587	[3]	94,703	[7]
Revisions of previous estimates	(1,217,253)	[8]	(1,047,353)	[9]
Production	(853,633)		(1,129,951)
Balance	17,065,540		18,181,839		20,264,440
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance | Mcf	8,769,538		9,962,790
Balance proved developed reserves | Mcf	9,202,098		4,733,090		4,126,780
Balance proved undeveloped reserves | Mcf	7,776,661		4,036,448		5,836,010
Acquisition | Mcf	0
Extensions, discoveries and other additions | Mcf	668,211	[3]	50,978	[7]
Revisions of previous estimates | Mcf	8,465,491	[8]	(395,183)	[9]
Production | Mcf	(924,481)		(849,047)
Balance | Mcf	16,978,759		8,769,538		9,962,790
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance	1,423,411		1,492,085
Balance proved developed reserves	1,210,323		774,311		686,765
Balance proved undeveloped reserves	1,014,367		649,100		805,320
Acquisition	0
Extensions, discoveries and other additions	122,579	[3]	7,664	[7]
Revisions of previous estimates	820,183	[8]	50,422	[9]
Production	(141,483)		(126,760)
Balance	2,224,690		1,423,411		1,492,085
Acquisition No. 1 [Member]
Reserve Quantities [Line Items]
Acquisition			0
Acquisition No. 1 [Member] | Oil [Member]
Reserve Quantities [Line Items]
Acquisition			0
Acquisition No. 1 [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Acquisition | Mcf			0
Acquisition No. 1 [Member] | Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Acquisition			0

[1] The annual review of the PUDs resulted in a positive revision of approximately 698 MBOE. This revision was the result of 724 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2019, 21 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, and 5 MBOE of downward adjustments attributable to changes in the future drill schedule.

[2] The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019, and 9 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.

[3] In 2020, extensions, discoveries and other additions of 1,189 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.

[4] In 2019, extensions, discoveries and other additions of 52 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.

[5] The Partnership converted 34 wells to proved developed reserves during 2020 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 1,909 MBOE.

[6] The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE.

[7] In 2019, extensions, discoveries and other additions of 111 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.

[8] Revisions to previous estimates increased proved reserves by 1,014 MBOE. The impact of these revisions had differing impacts to the Partnership’s oil, natural gas and NGL volumes. The revisions for oil volumes include 735 MBOE of downward adjustments attributable to well performance, 448 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019. The revisions for natural gas and NGL volumes include 1,800 MBOE of upward adjustments attributable to well performance, 443 MBOE of upward adjustments attributable to changes in the future drill schedule, and 11 MBOE of downward adjustments caused by lower oil prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019.

[9] Revisions to previous estimates decreased proved reserves by 1,063 MBOE. These revisions result from 804 MBOE of downward adjustments attributable to well performance, 246 MBOE of downward adjustments attributable to changes in the future drill schedule and 13 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018.

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Abstract]
Future cash inflows	$ 510,534	$ 888,271
Future production costs	(233,563)	(244,165)
Future development costs	(83,551)	(88,056)
Future net cash flows	193,420	556,050
10% annual discount	(125,407)	(312,901)
Standardized measure of discounted future net cash flows	$ 68,013	$ 243,149	$ 370,495

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure (Parentheticals)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Measurement Input, Discount Rate [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Annual discount	10.00%	10.00%

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Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Abstract]
Standardized measure at beginning of period	$ 243,149	$ 370,495
Changes resulting from:
Acquisition of reserves	0	0
Extensions, discoveries and other additions	7,889	1,093
Sales of oil, natural gas and NGLs, net of production costs	(16,534)	(41,631)
Net changes in prices and production costs	(149,606)	(97,776)
Development costs incurred during the period	8,852	32,229
Revisions to previous estimates	(45,739)	(40,287)
Accretion of discount	24,349	37,101
Change in estimated future development costs	(4,347)	(18,075)
Standardized measure of discounted future net cash flows	$ 68,013	$ 243,149

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Quarterly Financial Data (Unaudited) (Details) - Quarterly Financial Information - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Quarterly Financial Information [Abstract]
Total revenue	$ 11,888,952	$ 7,903,439	$ 3,189,431	$ 11,932,896	$ 18,352,989	$ 15,883,884	$ 18,832,114	$ 11,361,830	$ 34,914,718	$ 64,430,817
Net income (loss)	$ 1,398,501	$ (76,659)	$ (2,824,856)	$ 2,214,315	$ 2,741,099	$ 5,680,657	$ 8,277,089	$ 1,641,943	$ 711,301	$ 18,340,788
Basic and diluted net income (loss) per common share (in Dollars per share)	$ 0.13	$ (0.01)	$ (0.26)	$ 0.20	$ 0.25	$ 0.56	$ 0.92	$ 0.20	$ 0.06	$ 1.92

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Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Feb. 28, 2021	Jan. 31, 2021
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 1.2	$ 1.5
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.107397	$ 0.134247