As confidentially submitted to the Securities and Exchange Commission on February 13, 2018

Registration No. 333-            

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Confidential Draft Submission No. 1

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Berry Petroleum Corporation

(Exact Name of Registrant as Specified in its Charter)

Delaware	1311	81-5410470
(State or other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification Number)

5201 Truxtun Ave., Bakersfield, California 93309

(661) 616-3900

(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

Arthur T. Smith

President and Chief Executive Officer

5201 Truxtun Ave., Bakersfield, California 93309

(661) 616-3900

(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)

Copies to:

Douglas E. McWilliams

Sarah K. Morgan

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002-6760

(713) 758-2222

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ☐

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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	☒  (Do not check if a smaller reporting company)	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 7(a)(2)(B) of the Securities Act.  ☐

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee(3)
Common Stock, par value $0.001 per share	$	$

(1) Includes common stock issuable upon exercise of the underwriters’ option to purchase additional common stock.

(2) Estimated solely for the purpose of calculating the registration fee pursuant to rule 457(o) under the Securities Act of 1933, as amended.

(3) To be paid in connection with the initial filing of the registration statement.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state or jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated             , 2018

             Shares

Berry Petroleum Corporation

Common Stock

This is the initial public offering of the common stock of Berry Petroleum Corporation, a Delaware corporation. We are selling              shares of our common stock, and the selling stockholders are selling              shares of our common stock. We will not receive any proceeds from the shares of our common stock sold by the selling stockholders.

We anticipate that the initial public offering price will be between $             and $             per share. We intend to apply to list our common stock on the                          under the symbol “            .”

We have granted the underwriters the option to purchase up to an additional              shares of common stock on the same terms and conditions set forth above if the underwriters sell more than              shares of common stock in this offering.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012 and, as such, are eligible for reduced reporting requirements. Please see “Prospectus Summary—Emerging Growth Company Status”.

Investing in our common stock involves risks. Please see “Risk Factors” beginning on page 24 of this prospectus.

	Per share	Total(1)
Public offering price	$	$
Underwriting discount(1)	$	$
Proceeds to Berry Petroleum Corporation (before expenses)	$	$
Proceeds to the selling stockholders	$	$

(1) We refer you to “Underwriting (Conflict of Interest)” beginning on page 152 of this prospectus for additional information regarding underwriting compensation.

The underwriters expect to deliver the shares on or about             , 2018

Neither the U.S. Securities and Exchange Commission nor any state securities commission has approved or disapproved of the these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is             , 2018

TABLE OF CONTENTS

PROSPECTUS SUMMARY	1
RISK FACTORS	24
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	43
USE OF PROCEEDS	45
DIVIDEND POLICY	46
CAPITALIZATION	47
DILUTION	48
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA	50
PRO FORMA FINANCIAL DATA	52
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	60
BUSINESS	92
MANAGEMENT	129
EXECUTIVE COMPENSATION	134
PRINCIPAL AND SELLING STOCKHOLDERS	135
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	137
DESCRIPTION OF CAPITAL STOCK	139
SHARES ELIGIBLE FOR FUTURE SALE	145
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS	148
UNDERWRITING (CONFLICTS OF INTEREST)	152
LEGAL MATTERS	157
EXPERTS	157
WHERE YOU CAN FIND MORE INFORMATION	157
INDEX TO FINANCIAL STATEMENTS	F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS	A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we, the selling stockholders nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information. We, the selling stockholders and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date. This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please see “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Through and including                    , 2018 (the 25th day after the date of this prospectus), all dealers effecting transactions in our shares, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

i

BASIS OF PRESENTATION

In 2013, LINN Energy, LLC (“LINN Energy”) and LinnCo, LLC (collectively, the “Linn Entities”) acquired Berry LLC for LinnCo, LLC shares and assumed debt with an aggregate value of $4.6 billion. A severe industry downturn coupled with the Linn Entities and Berry LLC’s high leverage and significant fixed charges, led the Linn Entities, and consequently, Berry LLC, to initiate petitions for reorganization in the U.S. Bankruptcy Court (the “Bankruptcy Court”) for the Southern District of Texas (collectively, the “Chapter 11 Proceeding”) on May 11, 2016. In anticipation of emergence, Berry Corp. was formed for the purpose of having all the membership interests of Berry LLC assigned to it upon Berry LLC’s emergence from bankruptcy. On February 28, 2017 (the “Effective Date”), all of Berry LLC’s outstanding membership interests were transferred to Berry Corp., and Berry LLC emerged from bankruptcy as a wholly-owned subsidiary of Berry Corp., separate from the Linn Entities. Upon our emergence, we adopted fresh-start accounting, which, with the recapitalization described above, resulted in Berry Corp. being treated as the new entity for financial reporting. Unless otherwise noted or suggested by context, all financial information and data and accompanying financial statements and corresponding notes, as contained in this prospectus, (i) on or prior to the Effective Date, reflect the actual historical results of operations and financial condition of Berry LLC for the periods presented and do not give effect to the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry LLC (the “Plan”) or any of the transactions contemplated thereby or the adoption of fresh-start accounting, and (ii) following the Effective Date, reflect the actual historical results of operations and financial condition of Berry Corp. on a consolidated basis and give effect to the Plan and any of the transactions contemplated thereby and the adoption of fresh-start accounting. Thus, the financial information presented herein on or prior to the Effective Date may not be comparable to our performance or financial condition after the Effective Date.

The financial information and certain other information presented in this prospectus has been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this prospectus. In addition, certain percentages presented in this prospectus reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding.

INDUSTRY AND MARKET DATA

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we, the selling stockholders nor the underwriters have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

TRADEMARKS AND TRADE NAMES

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

ii

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the information under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes to those financial statements appearing elsewhere in this prospectus. The information presented in this prospectus assumes an initial public offering price of $             per share (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters do not exercise their option to purchase additional shares of common stock. You should read “Risk Factors” for information about important risks that you should consider carefully before investing in our common stock.

Except with respect to historical financial information and data and accompanying financial statements and corresponding notes or as otherwise noted or the context requires otherwise, when we use the terms “we,” “us,” “our,” the “Company,” or similar words in this prospectus, (i) on or prior to the Effective Date, we are referring to Berry LLC, and (ii) following the Effective Date, we are referring to Berry Corp. and its subsidiary, Berry LLC, as applicable. When we refer to “our predecessor company,” we are referring to Berry LLC as it existed on or prior to the Effective Date. This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in “Annex A: Glossary of Oil and Natural Gas Terms.”

Our Company

We are a value-driven, independent oil and natural gas company engaged primarily in the development and production of conventional reserves located in the western United States, including California, Utah, Colorado and Texas. We target onshore, low-cost, low-risk, oil-rich basins, such as the San Joaquin basin of California and the Uinta basin of Utah. The Company’s assets are characterized by:

• high oil content with production consisting of approximately 82% oil;

• long-lived reserves with low and predictable production decline rates;

• an extensive inventory of low-risk development drilling opportunities with attractive full-cycle economics;

• a stable and predictable development and production cost structure; and

• favorable Brent-influenced crude oil pricing dynamics.

Our asset base is concentrated in the San Joaquin basin in California, which has over 100 years of production history and substantial remaining original oil in place. We focus on conventional, shallow reservoirs, the drilling and completion of which are low-cost in contrast to modern unconventional resource plays. Our decades-old proven completion techniques include cyclic or continuous steam injection (“steamflood”) and low-volume fracture stimulation.

We focus on enhancing our production, improving drilling and completion techniques, controlling costs and maximizing the ultimate recovery of hydrocarbons from our assets, with the goal of generating top-tier returns. We seek to fund repeatable organic production and reserves growth through the use of internally generated free cash flow from operations after debt service, or levered free cash flow, while also maintaining ample liquidity and a conservative financial leverage profile.

1

As of November 30, 2017, we had estimated proved reserves of 141,838 MBoe, of which approximately 57% were proved developed producing reserves and approximately 66% of total proved reserves were located in California. For the three months ended September 30, 2017, pro forma for the Hugoton Disposition and the Hill Acquisition (each as defined below), we had average production of approximately 27.0 MBoe/d, of which approximately 82% was oil.

The New Berry

Berry was founded by the entrepreneur and our namesake C. J. Berry in the late 1800s. After making his fortune working a solo-mining operation during the Alaskan gold rush, Mr. Berry returned to California and continued his success with oil exploration and production. Our predecessor company was formed in 1985 after merging several related entities and ultimately became publicly traded beginning in 1987.

In 2013, the Linn Entities acquired our predecessor company for LinnCo, LLC shares and assumed debt with an aggregate value of $4.6 billion. A severe industry downturn, coupled with high leverage and significant fixed charges, led the Linn Entities and, consequently, our predecessor company to initiate the Chapter 11 Proceeding on May 11, 2016.

On February 28, 2017, Berry LLC emerged from bankruptcy as a stand-alone company and wholly-owned subsidiary of Berry Corp. with new management, a new board of directors and new ownership. Through the Chapter 11 Proceeding, the Company significantly improved its financial position from that of Berry LLC while it was owned by the Linn Entities. These improvements included:

• the elimination of approximately $1.3 billion of debt and more than $76 million of annualized interest expense;

• the termination of, or renegotiation of more favorable terms for, several firm transportation and oil sales contracts; and

• the anticipated reduction in recurring general and administrative costs as a stand-alone company by following a lean operating model.

Today, we foster Mr. Berry’s entrepreneurial spirit and leadership skills. We encourage our teams to apply his business ethos at every level to move us forward. We strive to have a positive presence in the communities surrounding our operations. Our employees belong to the communities where they work, which we believe aligns our interests with those of the people who live near our operations.

Our Reserves and Assets

The majority of our reserves are composed of heavy crude oil in shallow, long-lived reservoirs. Approximately two-thirds of our proved reserves and approximately 90% of the PV-10 value of our proved reserves are derived from our assets in California. We also operate in the Uinta basin in Utah, a stacked, multi-bench, light-oil-prone play with significant undeveloped resources, in the Piceance basin in Colorado, a low geologic risk, prolific natural gas play, and in part of an extensive over-pressured natural gas cell on the western flank of the East Texas basin.

2

The charts below summarize certain characteristics of our proved reserves and PV-10 of proved reserves as of November 30, 2017 (as described in the table below and in “—Summary Reserves and Operating Data”):

1P Reserves by Category (142 MMBoe)	1P Reserves By Commodity (142 MMBoe)
1P Reserves By Area (142 MMBoe)	1P PV-10 by Area ($1.1 billion)

The tables below summarize our proved reserves and PV-10 by category as of November 30, 2017:

	Proved Reserves and PV-10 as of November 30, 2017(1)
	Oil (MMBbl)		Natural Gas (Bcf)		NGLs (MMBbl)		Total (MMBoe)		% of Proved		% Proved Developed		Capex(2) ($MM)		PV-10(3) ($MM)
PDP		63		101		1		81		57		93	$	51	$	741
PDNP		6		—		—		6		4		7		10		85
PUDs		32		137		—		55		39		—		489		243
Total		101		238		1		142		100		100	$	550	$	1,069

(1) Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with Securities and Exchange Commission (“SEC”) guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $53.40 per Bbl ICE (Brent) for oil and NGLs and $3.01 per MMBtu NYMEX Henry Hub for natural gas at November 30, 2017. Prices were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules, including adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Please see “—Summary Reserves and Operating Data.”

(2) Represents undiscounted future capital expenditures as of November 30, 2017.

(3) PV-10 is a financial measure that is not calculated in accordance with United States generally accepted accounting principles (“GAAP”). For a definition of PV-10, please read “—Summary Reserves and Operating Data—PV-10.” PV-10 does not give effect to derivatives transactions. With respect to PV-10 calculated as of November 30, 2017, it is not practical to calculate the taxes for such period because GAAP does not provide for disclosure of standardized measure on an interim basis.

3

The table below summarizes our average net daily production by basin for the three months ended September 30, 2017, pro forma for the Hugoton Disposition and the Hill Acquisition:

	Pro Forma Average Net Daily Production for the Three Months Ended September 30, 2017
	(MBoe/d)		Oil (%)
California		19.8		100	%
Uinta basin		5.0		48	%
Piceance basin		1.1		2	%
East Texas basin		1.1		—
Total		27.0		82	%

Our Stable Production Base with Low Decline Rates

Our reserves are long-lived and characterized by relatively low production decline rates, which affords capital flexibility through commodity price cycles and allows for efficient hedging of significant quantities of future expected production. The chart below shows our average daily production for the three months ended September 30, 2017, pro forma for the Hill Acquisition and Hugoton Disposition and the estimated production profile of our PDP reserves, derived from our November 30, 2017 reserve report, based on the assumptions and calculations therein.

PDP Production by Year (MBoe/d) and PDP Decline Rates

Our Development Opportunities

We have an extensive inventory of low-risk, high-return development opportunities. Our inventory currently consists of 790 gross (786 net) identified drilling locations associated with proved undeveloped reserves as of November 30, 2017 with average EURs of approximately 46 MBoe in California and 360 MBoe in Colorado and average estimated drilling and completion costs of approximately $450,000 and $1,800,000, respectively. We also have approximately 1,305 gross (1,300 net) additional identified drilling locations with economics that management believes are similar to those of our proved undeveloped locations. We also have identified more than 3,800 gross (3,500 net) additional drilling locations, the economics of which are currently under review. Our identified drilling locations include 161 gross (161 net) steamflood and waterflood injection wells that we expect to add incremental production. For a discussion of how we identify drilling locations, please see “Business—Our Reserves and Production Information—Determination of Identified Drilling Locations.”

4

We operate over 95% of our productive wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, approximately 76% of our acreage is held by production, including 99% of our acreage in California. Our high degree of operational control, together with the large portion of our acreage that is held by production, gives us flexibility over the execution of our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production.

The following table summarizes certain information concerning our acreage, identified drilling locations and producing wells as of November 30, 2017:

	Acreage				Net Acreage Held By Production(%)			Producing Wells, Gross(1)(2)		Average Working Interest (%)(2)(4)			Net Revenue Interest (%)(2)(5)			Identified Drilling Locations (3)
	Gross		Net													Gross		Net
California		10,880		7,945		99	%		2,522		99	%		95	%		3,742		3,731
Uinta basin		143,120		98,804		72	%		912		95	%		79	%		1,246		1,084
Piceance basin		10,553		8,008		85	%		170		72	%		57	%		869		663
East Texas basin		5,853		4,533		100	%		117		99	%		79	%		123		122
Total		170,406		119,290		76	%		3,721		97	%		86	%		5,980		5,600

(1) Includes 469 steamflood and waterflood injection wells in California.

(2) Excludes 91 wells in the Piceance basin each with a 5% working interest and eleven wells in the Permian basin all with less than 0.1% working interest.

(3) Our total identified drilling locations include 790 gross (786 net) locations associated with PUDs as of November 30, 2017, including 161 gross (161 net) steamflood and waterflood injection wells. Please see “Business—Our Reserves and Production Information—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations.

(4) Represents our weighted average working interest in our active wells.

(5) Represents our weighted average net revenue interest for the month of September 2017.

Favorable Cost Structure

Our PDP assets are primarily mature, long-lived, oil-weighted, low-decline producing properties. The nature of our reserves requires relatively less development capital to maintain our base production, offsetting moderately higher per barrel operating expenses inherent in mature oil wells. Operating expenses includes lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses net of electricity sales and marketing revenues. In addition, our operating cost structure benefits from relatively stable service costs. As a result, our cost structure is stable and, given the nature of our production base, provides us with significant capital flexibility, and a low break-even operating price. Further, lack of need for advanced equipment in our key operations and the stable cost of the service environment drive substantially lower service costs and provide relative insulation from the cost inflation pressures experienced by our peers who operate primarily in unconventional plays.

Our PUD reserves are expected to have lower operating expenses per Boe compared to our PDP reserves due to the higher rates of production associated with new wells as compared to our older producing wells, which have been producing for an average of 11 years. Our lower expected operating expenses on our PUD reserves supports high full-commodity-cycle margins (including cost of development). The result of our PDP and PUD operating expenses mix is a stable total company cost structure over time, which provides significant through-cycle capital flexibility.

5

The following chart represents our expected operating expenses per Boe for the next five years as provided to our reserve engineers in connection with the preparation of our November 30, 2017 reserve report:

PUD / PDP Operating Expenses ($/Boe)

Our operating expense estimates are based on, among other things, our current cost structure. Investors should also recognize that the reliability of any guidance diminishes the farther in the future that data are forecast so that it is increasingly likely that our actual results will differ materially from our guidance. See “Risk Factors—Risks Related to Our Business and Industry.”

Other Assets

We produce oil from heavy crude reservoirs using steam to heat the oil so it will flow. Because of our dependence on steam, we own and operate five natural gas cogeneration plants. These plants supply approximately 24% of our steam needs and 43% of our field electricity needs in California at a discount to electricity market prices. To further offset our costs, we also sell surplus power produced by three of our cogeneration facilities under long-term contracts with California utility companies.

In addition, we own gathering, treatment and storage facilities in California that currently have excess capacity, reducing our need to spend capital to develop nearby assets and generally allowing us to control certain operating costs. We also own a network of oil and gas gathering lines across our assets outside of California, and our oil and natural gas is transported through such lines and third-party gathering systems and pipelines.

We own a natural gas processing plant with capacity of approximately 30 MMcf/d in the Brundage Canyon area, located in Duchesne County, Utah. This facility takes delivery from gathering and compressions facilities we operate. Approximately 95% of the gas gathered at these facilities is produced from wells that we operate. Current throughput at the processing plant is 18 to 20 MMcf/d and sufficient capacity remains for additional large-scale development drilling.

Our California Advantage

California is one of the most productive oil and natural gas regions in the world and was the third largest oil producing state in the United States in 2016 according to the U.S. Energy Information Administration (the “EIA”), with significant remaining opportunities for production growth with attractive full-cycle returns. The San Joaquin basin in California has produced for over a century. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present low-risk development opportunities. The majority of these reserves are composed of heavy crude oil in shallow, long-lived reservoirs with lower drilling risks and costs compared to deeper reservoirs or shale resource plays.

6

California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources, and there is a closer correlation of price in California to Brent pricing than to WTI. This dynamic has led to periods where the price for the primary benchmark, Midway-Sunset, a 13° API heavy crude, has been equal to or exceeded the price for WTI, a light 40° API crude.

Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low transportation costs, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.

Our Capital Budget

Following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities, we increased our pace of development and expect to continue to do so in 2018. Our 2018 anticipated capital expenditure budget of approximately $135 to $145 million represents an increase of approximately 84% over our expected 2017 capital expenditures of approximately $74 to $78 million. Based on current commodity prices and a drilling success rate comparable to our historical performance, we believe we will be able to fund our 2018 capital program with our levered free cash flow. We expect to:

• employ:

• two drilling rigs in California continuously through 2018; and

• one additional drilling rig assigned to certain projects in the second half of 2018;

• drill approximately 180 to 190 gross development wells, of which we expect at least 175 will be in California; and

• maintain a fairly constant pace of drilling throughout the year.

The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial condition and results of operations.

Our Commodity Hedging Program

We expect our operations to generate substantial cash flows at current commodity prices. We have protected a portion of our anticipated cash flows through 2020 as part of our crude oil hedging program. Our low-decline production base, coupled with our stable operating cost environment, affords us the ability to hedge a material amount of our future expected production. The chart below summarizes our derivative contracts in place as of January 4, 2018.

7

Hedge Volumes in MMBbls (MBbl/d)

Our Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategy.

• Stable, low-decline, predictable and oil-weighted conventional asset base. We expect our operations to continue to generate sufficient levered free cash flow at current commodity prices to fund maintenance operations and growth. The majority of our interests are in properties that have produced for decades. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present lower risk than unconventional resource plays. The properties are characterized by long-lived reserves with low production decline rates, a stable cost structures and low-risk developmental drilling opportunities with predictable production profiles. They provide a high degree of capital flexibility through commodity cycles.

• Substantial inventory of low-cost, low-risk and high-return development opportunities. We expect our locations to generate highly attractive rates of return. For example, our inventory includes 790 gross (786 net) identified drilling locations associated with proved undeveloped reserves with projected average single-well rates of return of approximately 40%, based on our assumptions used in preparing our November 30, 2017 reserve report, and approximately 1,305 gross (1,300 net) additional identified drilling locations with economics that management believes are similar to those of our proved undeveloped locations. In addition, we have approximately 3,800 additional identified drilling locations that are currently under review.

• Experienced, principled and disciplined management team. Our management team has significant experience operating and managing oil and gas businesses across numerous domestic and international basins, as well as reservoir and recovery types. We will employ our deep technical, operational and strategic management experience to optimize the value of our assets and the Company. We are focused on the principles of growing cash flows and the value of our production and reserves and take a disciplined approach to development and operating cost management, field development efficiencies and the application of proven technologies and processes new to our properties in order to generate a sustained cost advantage. We believe that our knowledge and operating experience, together with the quality of our assets, offer opportunities to increase value and that our value-driven approach to operational and strategic decisions will help us optimize our returns.

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• Substantial capital flexibility derived from a high degree of operational control and stable cost environment. We operate over 95% of our productive wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, approximately 76% of our acreage is held by production, including 99% of our acreage in California. Our high degree of operational control over our properties, together with the large portion of our acreage that is held by production, gives us flexibility over the execution of our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production. Our lack of need for advanced equipment in our key operations and the stable cost of the service environment drive substantially lower service costs and provide relative insulation from the cost inflation pressures experienced by our peers who operate primarily in unconventional plays. The more stable costs associated with our operations provide us significant visibility and understanding of our expected cash flows, which allow us to manage our business through commodity price cycles.

• Conservative balance sheet leverage with ample liquidity and minimal contractual obligations. After giving effect to this offering and repayment of borrowings under the RBL Facility (as defined herein), we expect to have approximately $             million of available liquidity, defined as cash on hand plus availability under our RBL Facility. In addition, we have minimal long-term service or fixed-volume delivery commitments. This liquidity and flexibility permit us to capitalize on opportunities that may arise to grow and increase stockholder value

• Brent-influenced pricing advantage. California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources. There is a closer correlation of prices in California to Brent pricing than to WTI. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.

Our Business Strategy

The principal elements of our business strategy include the following:

• Grow production and reserves in a capital efficient manner using internally generated cash flow. We intend to allocate capital in a disciplined manner to projects that will produce predictable and attractive rates of return. We plan to direct capital to our oil-rich and low-risk development opportunities while focusing on driving cost efficiencies across our asset base with the primary objective of internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins.

• Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we intend to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will explore innovative EOR techniques to unlock additional value and have allocated capital towards next generation technologies. For example, in our South Belridge Hill non-thermal and Midway-Sunset thermal diatomite properties, we employ both fracture stimulation and advanced thermal techniques, and in our Piceance properties, we use advanced proppant-less slick water fracture stimulation techniques. In addition, we intend to expand our geologic investigation of deeper reservoirs on our acreage and adjacent acreage below existing producing reservoirs and to expand strategic development beyond our known productive areas.

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• Proactively and collaboratively engage in matters related to regulation, safety, environmental and community relations. We are committed to proactive engagement with regulatory agencies in order to realize the full potential of our resources in a timely fashion that safeguards people and the environment and complies with law and regulations. We expect our work with regulators and legislators throughout the rule making process to minimize any adverse impact that new legislation and regulations might have on our ability to maximize our resources. We have found constructive dialogue with regulatory agencies can help avert compliance issues.

• Maintain balance sheet strength and flexibility through commodity price cycles. We intend to fund our capital program primarily through the use of internally generated levered free cash flow from operations. Over time, we expect to de-lever through organic growth and with excess levered free cash flow. Our objective is to achieve and maintain a long-term, through-cycle leverage ratio between 1.5x and 2.0x.

• Enhance future cash flow stability and visibility through an active and continuous hedging program. Our hedging strategy is designed to insulate our capital program from price fluctuations by securing price realizations and cash flows, including fixed-price gas purchase agreements and other hedging contracts. We have protected a portion of our anticipated production through 2020 as part of our crude oil hedging program. As of January 4, 2018, we have hedged approximately 6.4 MMBbls for 2018, 5.0 MMBbls for 2019 and 0.4 MMBbls for 2020 of crude oil production. We will review our hedging program continuously as conditions change.

Recent Developments

Hill Acquisition and Hugoton Disposition

On July 31, 2017, we sold our approximately 78% non-operated working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle (the “Hugoton Disposition”) and acquired the remaining approximately 84% non-operated working interest to consolidate with our existing 16% operated working interest in a South Belridge Hill property, located in Kern County, California, in the San Joaquin basin (the “Hill Acquisition”). These transactions significantly increased the percentage of our production that is oil, which benefits from California pricing margins, increased our future drilling opportunities, concentrated our assets and were essentially operating cash flow neutral at the time of the transactions. With the Hill Acquisition, we gained the remaining working interest in approximately 1,100 identified gross drilling locations. We used the proceeds of the Hugoton Disposition and cash on hand to complete the Hill Acquisition.

The table below compares certain aspects of the Hill Acquisition and the Hugoton Disposition:

	Hill Acquisition		Hugoton Disposition
Estimated PV-10 (millions)(1)(2)	$	290	$	190
Proved Reserves (MMBoe)(1)		24.7		62.6
Average Net Daily Production from January 1, 2017—September 30, 2017(Boe/d)		3,000		9,533
Revenue Equivalent Barrels of oil per day from January 1, 2017—September 30, 2017(1)(3)				3,650
Percent (%) product mix (Oil/Natural Gas Equivalent/NGLs for January 1, 2017—September 30, 2017)		100 / 0 / 0		0 / 66 / 34

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(1) We estimated reserve volumes and the PV-10 value of the Hugoton asset as of March 31, 2017 in accordance with SEC guidance. Reserves volumes and the PV-10 value of the Hill asset represents the value associated with the 84% non-operated working interest acquired in the Hill Acquisition and does not include the value associated with the 16% operated working interest already owned. We estimated reserve volumes of the Hill asset as of March 31, 2017 in accordance with SEC guidance. Primarily as a result of an increase in oil prices, the PV-10 value of the Hill asset has increased significantly since the completion of the Hill Acquisition. The PV-10 value in the table above is as of November 30, 2017. As of March 31, 2017, the PV-10 value of the Hill asset was approximately $216 million.

(2) PV-10 is a non-GAAP financial measure. For a definition of PV-10, please read “—Summary Reserves and Operating Data—PV 10.” PV-10 does not give effect to derivatives transactions.

(3) Because the Hugoton asset produced primarily natural gas and the Hill asset produces oil, revenue from the sale of 9,533 Boe/d from the Hugoton asset would be equal to revenue generated from the sale of 3,650 Boe/d at the Hill asset.

Senior Unsecured Notes Offering

In February 2018, we closed a private offering (the “2018 Notes Offering”) of $400 million principal amount of 7.000% senior unsecured notes due 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately $392 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the 2018 Notes Offering to repay borrowings under our $1.5 billion reserve base lending facility entered into on July 31, 2017, (the “RBL Facility”) and will use the remainder for general corporate purposes.

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors. You could lose all or part of your investment. You should bear in mind, in reviewing this prospectus, that past experience is no guarantee of future performance. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 24 for an explanation of these risks before investing in our common stock and “Cautionary Note Regarding Forward-Looking Statements” on page 43 of this prospectus. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities:

• Oil, natural gas and NGL prices are volatile.

• Our business requires substantial capital investments. We may be unable to fund these investments through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or production. Our capital investment program is also susceptible to risks that could materially affect its implementation.

• We may be unable to, or may choose not to, enter into sufficient fixed-price purchase or other hedging agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam operations economically or at desired levels.

• We may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.

• Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.

• Unless we replace oil and natural gas reserves, our future reserves and production will decline.

• We may not drill our identified sites at the times we scheduled or at all.

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

• We are dependent on our cogeneration facilities and deteriorations in the electricity market and regulatory changes in California may materially and adversely affect our financial condition, results of operations and cash flows.

• Future declines in commodity prices, changes in expected capital development, increases in operating costs or adverse changes in well performance may result in write-downs of the carrying amounts of our assets.

• The inability of one or more of our customers to meet their obligations may have a material adverse effect on our business, financial condition, results of operations and cash flows.

• Due to our limited operating history as an independent company following our emergence from bankruptcy in February 2017, we have been in the process of establishing our accounting and other management systems and resources. We may be unable to effectively develop a mature system of internal controls, and a failure of our control systems to prevent error or fraud may materially harm our company.

Emerging Growth Company Status

We are an “emerging growth company” as such term is used in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies, we will not be required to:

• provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley Act”);

• provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations;

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

• provide certain disclosure regarding executive compensation required of larger public companies or hold stockholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”); or

• obtain stockholder approval of any golden parachute payments not previously approved.

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

• the last day of the fiscal year in which we have $1.07 billion or more in annual revenues;

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

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

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

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In addition, under Section 107 of the JOBS Act emerging growth companies can also delay adopting new or revised accounting standards until such time as those standards apply to private companies. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

Corporate Information

We were incorporated in Delaware in February 2017. Our principal executive offices are located at 5201 Truxtun Ave., Bakersfield, California 93309 and we have additional executive offices located at 16000 N. Dallas Pkwy, Ste 100, Dallas, Texas 75248. Our telephone number is (661) 616-3900 and our web address is www.berrypetroleum.com. Information contained in or accessible through our website is not, and should not be deemed to be, part of this prospectus.

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The Offering

Issuer Berry Petroleum Corporation.

Common stock offered by us              shares (or              shares, if the underwriters exercise in full their option to purchase additional shares).

Common stock offered by the selling stockholders              shares.

Common stock outstanding after this offering              shares (or              shares, if the underwriters exercise in full their option to purchase additional shares).

Option to purchase additional shares We have granted the underwriters a 30-day option to purchase up to an aggregate of              additional shares of our common stock if the underwriters sell more than              shares of common stock in this offering.

Use of proceeds Assuming the midpoint of the price range set forth on the cover of this prospectus, we expect to receive approximately $             million of net proceeds from this offering after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We will not receive any proceeds from the sale of shares by the selling stockholders

We intend to use the proceeds from this offering to repay outstanding borrowings under the RBL Facility and for general corporate purposes. Please read “Use of Proceeds.”

Dividend policy We do not anticipate paying any cash dividends on our common stock. Please read “Dividend Policy.”

Listing and trading symbol We intend to apply to list our common stock on the              under the symbol “            .”

Risk factors You should carefully read and consider the information set forth under the heading “Risk Factors” on page 24 of this prospectus and all other information set forth in this prospectus before deciding to invest in our common stock.

The information above excludes shares of common stock reserved for issuance pursuant to our 2017 Long-Term Incentive Plan (our “2017 Incentive Plan”).

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Summary Historical and Pro Forma Financial Information

The summary historical financial information as of and for the years ended December 31, 2015 and 2016 are derived from the audited historical consolidated financial statements of Berry LLC included elsewhere in this prospectus. The summary historical financial information as of and for the nine months ended September 30, 2016 and for the two months ended February 28, 2017 are derived from unaudited consolidated financial statements of Berry LLC included elsewhere in this prospectus. The summary historical financial information for the seven months ended September 30, 2017, is derived from unaudited consolidated financial statements of Berry Corp. included elsewhere in this prospectus.

Upon Berry LLC’s emergence from bankruptcy on February 28, 2017, or the Effective Date, in connection with the Plan, Berry LLC adopted fresh-start accounting and was recapitalized, which resulted in Berry LLC becoming a wholly-owned subsidiary of Berry Corp. and Berry Corp. being treated as the new entity for financial reporting. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. These fair values differed materially from the recorded values of our assets and liabilities as reflected in Berry LLC’s historical consolidated balance sheet. The effects of the Plan and the application of fresh-start accounting are reflected in Berry Corp.’s consolidated financial statements as of the Effective Date and the related adjustments thereto are recorded in our consolidated statements of operations as reorganization items for the periods prior to the Effective Date. As a result, our consolidated financial statements subsequent to the Effective Date will not be comparable to our consolidated financial statements prior to such date. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

The summary unaudited pro forma financial information for the year ended December 31, 2016 is derived from the audited historical consolidated financial statements of Berry LLC included elsewhere in this prospectus. The summary unaudited pro forma financial information for the nine months ended September 30, 2017 is derived from unaudited consolidated financial statements of Berry LLC and Berry Corp. included elsewhere in this prospectus.

The summary unaudited pro forma financial information for the year ended December 31, 2016 and the nine months ended 2017 has been prepared to give pro forma effect to (i) the Plan and related transactions and fresh-start accounting and (ii) the Hugoton Disposition, as if each had been completed as of January 1, 2016, respectively. The summary unaudited pro forma financial information does not give effect to the Hill Acquisition because such transaction is not deemed significant under Rule 3-05 of the SEC’s Regulation S-X, so it is not required to be presented.

The summary unaudited pro forma financial information has been provided for informational and illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Plan or the Hugoton Disposition had been put into effect on the dates indicated, nor are such financial statements necessarily indicative of the financial position or results of operations in future periods.

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You should read the following summary information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the following information. The historical financial results are not necessarily indicative of results to be expected for any future period.

	Berry Corp.			Berry LLC
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
										2016			2015
	(unaudited)			(unaudited) ($ in thousands)						(audited)			(audited)
Statements of Operations Data:
Oil, natural gas and NGL liquid sales	$	237,324		$	74,120		$	285,538		$	392,345		$	575,031
Electricity sales		15,517			3,655			17,573			23,204			24,544
(Losses) gains on oil and natural gas derivatives		5,642			12,886			1,642			(15,781	)		29,175
Marketing revenues		1,901			633			2,743			3,653			5,709
Other revenues		3,902			1,424			5,634			7,570			7,195
Lease operating expenses		108,751			28,238			138,557			185,056			245,155
Electricity generation expenses		10,192			3,197			12,118			17,133			18,057
Transportation expenses		18,645			6,194			32,518			41,619			52,160
Marketing expenses		1,674			653			2,173			3,100			3,809
Taxes, other than income taxes		25,113			5,212			20,614			25,113			70,593
General and administrative expenses(1)		39,791			7,964			65,313			79,236			85,993
Reorganization items, net		(1,001	)		(507,720	)		(38,829	)		(72,662	)		—
Depreciation, depletion and amortization		48,392			28,149			139,980			178,223			251,371
Interest expense		(12,482	)		(8,245	)		(48,719	)		(61,268	)		(85,818	)
Income tax (benefit) expense		9,190			230			196			116			(68	)
Net (loss) income		13,812			(502,964	)		(1,216,417	)		(1,283,196	)		(1,015,177	)
Cash Flow Data:
Net cash provided by (used in)
Operating activities		88,364			(30,176	)		3,269			12,345			122,518
Capital expenditures		(52,572	)		(3,158	)		(26,534	)		(34,796	)		(50,374	)
Acquisitions, sales of properties and other investing activities		(21,991	)		25			53,590			53,612			151,742
Balance Sheets Data:
(at period end)
Total assets	$	1,579,389		$	1,561,038		$	2,681,256		$	2,652,050		$	3,861,476
Current portion of long-term debt		—			—			891,259			891,259			873,175
Long-term debt, net		379,000			400,000			—			—			845,368
Series A Preferred Stock		335,000			335,000
Stockholders’ and/or member’s equity		877,541			862,827			569,741			502,963			1,786,159
Other Financial Data:
Adjusted EBITDA(2)	$	96,773		$	28,845		$	54,429		$	89,646		$	206,537
Adjusted General and Administrative Expenses(3)		11,468			7,964			65,313			79,236			85,993

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(1) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $28.3 million for the seven months ended September 30, 2017.

(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

(3) Adjusted General and Administrative Expenses is a non-GAAP financial measure. For a definition of Adjusted General and Administrative Expenses and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

	Pro Forma
	Nine Months Ended September 30,			Year Ended December 31,
	2017			2016
	($ in thousands)
Statements of Operations Data:
Oil, natural gas and NGL liquid sales	$	273,602		$	343,169
(Losses) gains on oil and natural gas derivatives		18,528			(15,781	)
Lease operating expenses		130,860			176,669
Transportation expenses		14,832			25,943
Taxes, other than income taxes		25,457			22,338
General and administrative expenses(1)		46,463			77,712
Reorganization items, net		(1,001	)		—
Depreciation, depletion and amortization		55,751			61,514
Interest expense, net of amounts capitalized		(15,797	)		(20,228	)
Income tax (benefit) expense		4,871			116
Net (loss) income		7,338			(1,080,846	)

(1) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $28.3 million for the nine months ended September 30, 2017.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion; exploration expense, derivative gains or losses net of cash received for derivative settlements; impairments, stock compensation expense, and other unusual out-of-period and infrequent items, including restructuring and reorganization costs.

Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. While Adjusted EBITDA is a non-GAAP measure, the amounts included in the calculation of Adjusted EBITDA were computed

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in accordance with GAAP. This measure is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income (loss) for each of the periods indicated.

	Berry Corp.			Berry LLC
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
										2016			2015
							($ in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	13,812		$	(502,964	)	$	(1,216,417	)	$	(1,283,196	)	$	(1,015,177	)
Add (Subtract):
Depreciation, depletion, amortization and accretion		48,392			28,149			139,980			178,223			251,371
Exploration expense		—			—			—			—			—
Interest expense		12,482			8,245			48,719			61,268			85,818
Income tax expense (benefit)		9,190			230			196			116			(68	)
Derivative (gain) loss		(5,642	)		(12,886	)		2,963			20,386			(36,068	)
Net cash received for derivative settlements		9,902			534			9,708			9,708			68,770
(Gain) on sale of assets and other		(20,687	)		(183	)		(137	)		(109	)		(1,919	)
Impairments		—			—			1,030,588			1,030,588			853,810
Stock compensation expense		902			—			—			—			—
Restructuring costs		27,421			—			—			—			—
Reorganization items, net		1,001			507,720			38,829			72,662			—
Adjusted EBITDA	$	96,773		$	28,845		$	54,429		$	89,646		$	206,537

Adjusted General and Administrative Expenses

Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by management. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-recurring restructuring and other costs and non-cash stock compensation expense.

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Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period. We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency. Adjusted General and Administrative Expenses should not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted General and Administrative Expenses to the GAAP financial measure of general and administrative expenses for each of the periods indicated.

	Berry Corp.			Berry LLC
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017		Nine Months Ended September 30, 2016		Year Ended December 31,
								2016		2015
						($ in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expense:
General and administrative expense	$	39,791		$	7,964	$	65,313	$	79,236	$	85,993
Subtract:
Non-recurring restructuring and other costs		(27,421	)		—		—		—		—
Non-cash stock compensation expense		(902	)		—		—		—		—
Adjusted General and Administrative Expenses	$	11,468		$	7,964	$	65,313	$	79,236	$	85,993

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Summary Reserves and Operating Data

The following tables present summary data with respect to our estimated proved oil, natural gas and NGL reserves and operating data as of the dates presented. In evaluating the material presented below, please read “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Our Reserves and Production Information” and our financial statements and notes thereto. Our historical results of operations are not necessarily indicative of results to be expected for any future period.

Reserves

The following table summarizes our estimated proved reserves and related PV-10 at November 30, 2017. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton. The reserve estimates were prepared in accordance with current SEC rules and regulations regarding oil, natural gas and NGL reserve reporting. Reserves are stated net of applicable royalties.

	At November 30, 2017(1)
	San Joaquin and Ventura basins		Uinta basin		Piceance basin		East Texas basin		Total
Proved developed reserves:
Oil (MMBbl)		62		7		—		—		69
Natural Gas (Bcf)		—		47		43		12		101
NGLs (MMBbl)		—		1		—		—		1
Total (MMBoe)(2)(3)		62		16		7		2		87
Proved undeveloped reserves:
Oil (MMBbl)		32		—		—		—		32
Natural Gas (Bcf)		—		—		137		—		137
NGLs (MMBbl)		—		—		—		—		—
Total (MMBoe)(3)		32		—		23		—		55
Total proved reserves:
Oil (MMBbl)		93		7		—		—		101
Natural Gas (Bcf)		—		47		179		12		238
NGLs (MMBbl)		—		1		—		—		1
Total (MMBoe)(3)		93		16		30		2		142
PV-10 ($MM)		952		82		27		8		1,069

(1) Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $53.40 per Bbl ICE (Brent) for oil and NGLs and $3.01 per MMBtu NYMEX Henry Hub for natural gas at November 30, 2017. Prices were calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For more information regarding commodity price risk, please see “Risk Factors—Risks Related to Our Business and Industry—Oil, natural gas and NGL prices are volatile.”

(2) Approximately 9% of proved developed oil reserves, 1% of proved developed NGLs reserves, 0% of proved developed natural gas reserves and 7% of total proved developed reserves are non-producing.

(3) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has

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been similarly lower for a number of years. For example, in the nine months ended September 30, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $52.59 per Bbl and $3.17 per Mcf, respectively, resulting in an oil-to-gas ratio of over 16 to 1.

PV-10

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

With respect to PV-10 calculated as of November 30, 2017, it is not practical to calculate the taxes for such period because GAAP does not provide for disclosure of standardized measure on an interim basis.

Production and Operating Data

The following table sets forth information regarding production, realized and benchmark prices, and production costs (i) on a historical basis for the years ended December 31, 2016 and 2015, for the two months ended February 28, 2017, the seven months ended September 30, 2017 and the nine months ended September 30, 2016 and (ii) on a pro forma basis for the nine months ended September 30, 2017.

The pro forma information has been prepared to give pro forma effect to (i) the Plan and related transactions and fresh-start accounting and (ii) the Hugoton Disposition, as if each had been completed as of January 1, 2016, respectively. The summary unaudited pro forma financial information does not give effect to the Hill Acquisition because such transaction is not deemed significant under Rule 3-05 of the SEC’s Regulation S-X, so it is not required to be presented herein. For more information, see “—Summary Historical and Pro Forma Financial Information.”

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For additional information regarding pricing dynamics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Environment and Market Conditions.”

	Pro Forma(5)			Berry Corp.						Berry LLC
	Nine Months Ended September 30,			Seven Months Ended			Two Months Ended			Nine Months Ended			Year Ended December 31,
	2017			September 30, 2017			February 28, 2017			September 30, 2016			2016			2015
Production Data:
Oil (MBbl/d)		19.9			20.0			19.5			23.9			23.1			30.0
Natural gas (MMcf/d)		31.1			57.2			71.7			78.6			78.1			92.7
NGLs (MBbl/d)		0.6			2.6			5.2			3.7			3.6			2.9
Average daily combined production (MBoe/d)(1)		25.7			32.2			36.6			40.7			39.7			48.4
Total combined production (MBoe)(1)		7,018			6,880			2,162			11,160			14,533			17,666
Average realized prices(2):
Oil (per Bbl)	$	45.31		$	44.86		$	46.94		$	34.00		$	35.83		$	42.27
Natural gas (per Mcf)	$	2.85		$	2.69		$	3.42		$	2.15		$	2.31		$	2.66
NGLs (per Bbl)	$	17.67		$	21.67		$	18.20		$	16.08		$	17.67		$	20.27
Average Benchmark prices:
ICE (Brent) oil ($/Bbl)	$	52.59		$	51.70		$	55.72		$	42.97		$	45.00		$	53.64
NYMEX Henry Hub natural gas ($/Mcf)	$	3.17		$	3.03		$	3.66		$	2.29		$	2.46		$	2.66
Average costs per Boe(3):
Lease operating expenses	$	18.65		$	15.81		$	13.06		$	12.42		$	12.73		$	13.88
Electricity generation expenses	$	1.91		$	1.48		$	1.48		$	1.09		$	1.18		$	1.02
Electricity sales	$	(2.73	)	$	(2.26	)	$	(1.69	)	$	(1.57	)	$	(1.60	)	$	(1.39	)
Transportation expenses	$	2.11		$	2.71		$	2.86		$	2.91		$	2.86		$	2.95
Marketing expenses	$	0.33		$	0.24		$	0.30		$	0.19		$	0.21		$	0.22
Marketing revenues	$	(0.36	)	$	(0.28	)	$	(0.29	)	$	(0.25	)	$	(0.25	)	$	(0.32	)
Taxes, other than income taxes	$	3.63		$	3.65		$	2.41		$	1.85		$	1.73		$	4.00
General and Administrative Expenses(4)	$	6.62		$	5.78		$	3.68		$	5.85		$	5.45		$	4.87
Depreciation, depletion and amortization	$	7.94		$	7.03		$	13.02		$	12.54		$	12.26		$	14.23

(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the nine months ended September 30, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $52.59 per Bbl and $3.17 per Mcf, respectively, resulting in an oil-to-gas ratio of over 16 to 1.

(2) Does not include the effect of gains (losses) on derivatives.

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(3) We report electricity and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties.

(4) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $28.3 million for the seven and nine months ended September 30, 2017.

(5) Does not include the effects of the Hill Acquisition. We estimate that the production associated with the Hill asset for the nine months ended September 30, 2017 was approximately 3,000 Boe/d.

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RISK FACTORS

An investment in our common stock involves a number of risks. You should carefully consider each of the following risk factors and all of the other information set forth in this prospectus before making an investment decision. If any of the following risks actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. If any of these risks occur, the trading price of our common stock could decline and you may lose all or part of your investment.

Risks Related to Our Business and Industry

The risks and uncertainties described below are among the items we have identified that could materially adversely affect our business, production, growth plans, reserves quantities or value, operating or capital costs, financial condition and results of operations and our ability to meet our capital expenditure and obligations and financial commitments.

Oil, natural gas and NGL prices are volatile.

The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital, future rate of growth and the carrying value of our properties. Prices for these commodities have, and may continue to, fluctuate widely in response to market uncertainty and to relatively minor changes in the supply of and demand for oil, natural gas and NGLs. For example, the Brent spot price for oil declined from a high of over $115.06 per Bbl on June 19, 2014 to a low of $27.88 per Bbl on January 20, 2016, and the Henry Hub spot price for natural gas declined from a high of $6.15 per MMBtu on February 19, 2014 to a low of $1.64 per MMBtu on March 3, 2016. While prices remain lower than the 2014 and 2015 averages, they have improved since early 2016. However, such improvements may not continue or may be reversed. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:

• worldwide and regional economic conditions impacting the global supply and demand for, and transportation costs of, oil and natural gas;

• the price and quantity of foreign imports of oil;

• political and economic conditions in, or affecting, other producing regions or countries, including the Middle East, Africa, South America and Russia;

• the level of global exploration, development, production and resulting inventories;

• actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;

• actions of other significant producers;

• prevailing prices on local price indexes in the areas in which we operate;

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

• the cost of exploring for, developing, producing and transporting reserves;

• weather conditions and natural disasters;

• technological advances, conservation efforts and availability of alternative fuels affecting oil and gas consumption;

• refining and processing disruptions or bottlenecks;

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• the impact of the U.S. dollar exchange rates on oil;

• expectations about future oil and gas prices; and

• Foreign and U.S. federal, state and local and non-U.S. governmental regulation and taxes.

Lower oil prices may reduce our cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected.

Also, lower prices generally adversely affect the quantity of our reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. In addition, a portion of our PUD reserves may no longer meet the economic producibility criteria under the applicable rules or may be removed due to a lower amount of capital available to develop these projects within the SEC-mandated five-year limit.

In addition, sustained periods with oil and natural gas prices at levels lower than current prices also may adversely affect our drilling economics, which may require us to postpone or eliminate all or part of our development program, and result in the reduction of some of our proved undeveloped reserves, which would reduce the net present value of our reserves.

Our business requires substantial capital investments. We may be unable to fund these investments through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or production. Our capital investment program is also susceptible to risks that could materially affect its implementation.

Our industry is capital intensive. We make and expect to continue to make substantial capital investments for the development and exploration of our oil and natural gas reserves. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction or sustained decline in commodity prices from current levels may force us to reduce our capital expenditures, which would negatively impact our ability to grow production. We have a 2018 capital expenditure budget of approximately $135 million to $145 million. We expect to fund our 2018 capital expenditures with cash flows from our operations; however, our cash flows from operations and access to capital should such cash flows prove inadequate are subject to a number of variables, including:

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

• the prices at which our production is sold and our operating expenses;

• the extent and levels of our derivatives activities;

• our proved reserves, including our ability to acquire, locate and produce new reserves;

• our ability to borrow under the RBL Facility; and

• our ability to access the capital markets.

If our revenues or the borrowing base under the RBL Facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital were needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If we are able to obtain debt financing, it would require that a portion of our cash flows from operations be used to service such indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions. If cash flows generated by our operations or available borrowings under the RBL Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result

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in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production and have an adverse effect on our business, financial condition and results of operations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

We may be unable to, or may choose not to, enter into sufficient fixed-price purchase or other hedging agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam operations economically or at desired levels.

The development of our heavy oil in California is subject to our ability to generate sufficient quantities of steam using natural gas at an economically effective cost. As a result, we need access to natural gas at prices sufficiently lower than oil prices on an energy equivalent basis to economically produce our heavy oil. We seek to reduce our exposure to the potential unavailability of natural gas and to pricing by entering into fixed-price purchase agreements and other hedging transactions. We may be unable to, or may choose not to, enter into sufficient such agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam operations economically or at desired levels.

We may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.

As of January 4, 2018, we have hedged approximately 6.4 MMBbls for 2018, 5.0 MMBbls for 2019 and 0.4 MMBbls for 2020 of crude oil production. In the future, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.

Our current commodity-price risk-management activities may prevent us from realizing the full benefits of price increases above the levels determined under the derivative instruments we use to manage price risk. In addition, our commodity-price risk-management activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

• the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and

• an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.

Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to environmental protection and the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products. Federal, state and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

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See “Business—Regulation of Health, Safety and Environmental Matters” for a description of laws and regulations that affect our business. To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, maintenance, transportation, marketing, site remediation, decommissioning, abandonment, fluid injection and disposal and water recycling and reuse. Failure to comply may result in the assessment of administrative, civil and criminal fines and penalties and liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting our operations. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. Permanent restrictions imposed to protect threatened or endangered species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.

Our customers, including refineries and utilities, and the businesses that transport our products to customers are also highly regulated. For example, federal and state pipeline safety agencies have adopted or proposed regulations to expand their jurisdiction to include more gas and liquid gathering lines and pipelines and to impose additional mechanical integrity requirements. The state has adopted additional regulations on the storage of natural gas that could affect the demand or availability of such storage, increase seasonal volatility, or otherwise affect the prices we pay for fuel gas.

Costs of compliance may increase and operational delays or restrictions may occur as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations, each of which has occurred in the past.

Government authorities and other organizations continue to study health, safety and environmental aspects of oil and natural gas operations, including those related to air, soil and water quality, ground movement or seismicity and natural resources. Government authorities have also adopted or proposed new or more stringent requirements for permitting, well construction and public disclosure or environmental review of, or restrictions on, oil and natural gas operations. Such requirements or associated litigation could result in potentially significant added costs to comply, delay or curtail our exploration, development, fluid injection and disposal or production activities, and preclude us from drilling, completing or stimulating wells, which could have an adverse effect on our expected production, other operations and financial condition.

Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.

Estimation of reserves and related future net cash flows is a partially subjective process of estimating accumulations of oil and natural gas that includes many uncertainties. Our estimates are based on various assumptions, which may ultimately prove to be inaccurate, including:

• the similarity of reservoir performance in other areas to expected performance from our assets;

• the quality, quantity and interpretation of available relevant data;

• commodity prices (see “—Oil, natural gas and NGL prices are volatile.”);

• production and operating costs;

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• ad valorem, excise and income taxes;

• development costs;

• the effects of government regulations; and

• future workover and asset retirement costs.

Misunderstanding these variables, inaccurate assumptions, changed circumstances or new information could require us to make significant negative reserves revisions.

We currently expect improved recovery, extensions and discoveries to be our main sources for reserves additions. However, factors such as the availability of capital, geology, government regulations and permits, the effectiveness of development plans and other factors could affect the source or quantity of future reserves additions. Any material inaccuracies in our reserves estimates could materially affect the net present value of our reserves, which could adversely affect our borrowing base and liquidity under the RBL Facility, as well as our results of operations.

Unless we replace oil and natural gas reserves, our future reserves and production will decline.

Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Reduced capital investment may result in a decline in our reserves. Our ability to make the necessary long-term capital investments or acquisitions needed to maintain or expand our reserves may be impaired to the extent cash flow from operations or external sources of capital are insufficient. We may not be successful in developing, exploring for or acquiring additional reserves. Over the long-term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development, production and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable or economically desirable oil and natural gas production or may result in a downward revision of our estimated proved reserves due to:

• poor production response;

• ineffective application of recovery techniques;

• increased costs of drilling, completing, stimulating, equipping, operating, maintaining and abandoning wells; and

• delays or cost overruns caused by equipment failures, accidents, environmental hazards, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes and other matters.

Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.” In addition, our cost of drilling, completing and operating wells is often uncertain.

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

• delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on wastewater disposal, emission of greenhouse gases (“GHGs”), steam injection and well stimulation;

• pressure or irregularities in geological formations;

• shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for steam used in production or pressure maintenance;

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

• lack of available capacity on interconnecting transmission pipelines; and

• other market limitations in our industry.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to property, reserves and equipment, pollution, environmental contamination and regulatory penalties.

We may not drill our identified sites at the times we scheduled or at all.

We have specifically identified locations for drilling over the next several years, which represent a significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. We make assumptions that may prove inaccurate about the consistency and accuracy of data when we identify these locations. We cannot guarantee that these prospective drilling locations or any other drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring in the next three years represented approximately 2% of our total net undeveloped acreage at December 31, 2017.

Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.

The RBL Facility and the indenture governing our 2026 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. These agreements contain covenants, that, among other things, limit our ability to:

• incur or guarantee additional indebtedness;

• make loans to others;

• make investments;

• merge or consolidate with another entity;

• make dividends and certain other payments in respect of our equity;

• hedge future production or interest rates;

• create liens that secure indebtedness;

• transfer or sell assets;

• enter into transactions with affiliates; and

• engage in certain other transactions without the prior consent of the lenders.

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In addition, the RBL Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios, which may limit our ability to borrow funds to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of these limitations.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

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

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our RBL Facility and our 2026 Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors that may be beyond our control. If oil and natural gas prices were to deteriorate and remain at low levels for an extended period of time, our cash flows from operating activities may be insufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources were insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness would depend on the condition of the capital markets and our financial condition at such time, including the view of the markets of our credit risk after recent defaults. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with new covenants that further restrict business operations and opportunities. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our RBL Facility currently restricts our ability to dispose of assets and our use of the proceeds from any such disposition. We may not be able to consummate dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties for acquisitions and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ greater financial, technical and personnel resources than we do. In California, where we have the most experience operating, our competitors are few and large, which may limit available acquisition opportunities. Our competitors may also be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has historically continually increased due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

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We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets or enter into attractive joint ventures, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future, we may make acquisitions of assets or businesses that we believe complement or expand our current business. However, there is no guarantee we will be able to identify or complete attractive acquisition opportunities. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions. The success of completed acquisitions will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

In addition, our debt arrangements impose certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could indirectly limit our ability to acquire assets and businesses. See “—Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.”

We are dependent on our cogeneration facilities and deteriorations in the electricity market and regulatory changes in California may materially and adversely affect our financial condition, results of operations and cash flows.

We are dependent on five cogeneration facilities that, combined, provide approximately 24% of our steam capacity and 43% of our field electricity needs in California at a discount to market rates. These facilities are dependent on viable contracts for the sale of electricity. To further offset our costs, we sell surplus power to California utility companies produced by three of our cogeneration facilities under long-term contracts. Market fluctuations in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration facilities and any corresponding increase in the price of steam could significantly impact our operating costs. If we were unable to find new or replacement steam sources, to lose existing sources or to experience installation delays, we may be unable to maximize production from our heavy oil assets. If we were to lose our electricity sources, we would be subject to the electricity rates we could negotiate for our needs. For a more detailed discussion of our electricity sales contracts, see “Business—Operational Overview—Electricity.”

Future declines in commodity prices, changes in expected capital development, increases in operating costs or adverse changes in well performance may result in write-downs of the carrying amounts of our assets.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. We evaluate the impairment of our oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. For the year ended December 31, 2016, we recorded noncash impairment charges of approximately $1.0 billion. Future declines in oil, natural gas and NGL prices, changes in expected capital development, increases in operating costs or adverse changes in well performance, among other things, may require additional material write-downs of the carrying amounts of our assets, which could materially and adversely affect our results of operations in the period incurred.

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The inability of one or more of our customers to meet their obligations may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have significant concentrations of credit risk with the purchasers of our oil and natural gas. For the year ended December 31, 2016, sales of oil, natural gas and NGLs to Tesoro Corporation and Phillips 66 accounted for approximately 34% and 28%, respectively, of our sales.

Due to the terms of supply agreements with our customers, we may not know that a customer is unable to make payment to us until almost two months after production has been delivered. This concentration of purchasers may impact our overall credit risk in that these entities may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. If the purchasers of our oil and natural gas become insolvent, we may be unable to collect amounts owed to us.

Our producing properties are located primarily in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.

We operate primarily in California. Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to the effects of conditions there. These conditions include local price fluctuations, changes in state or regional laws and regulations affecting our operations, limited acquisition opportunities where we have the most operating experience and other regional supply and demand factors, including gathering, pipeline and transportation capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. For a discussion of regulatory risks, see “—Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy.” The concentration of our operations in California and limited local storage options also increase our exposure to events such as natural disasters, including wildfires, mechanical failures, industrial accidents or labor difficulties.

Operational issues and inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise could restrict access to markets for the commodities we produce.

Our ability to market our production of oil, gas and NGLs depends on a number of factors, including the proximity of production fields to pipelines and terminal facilities, competition for capacity on such facilities and the ability of such facilities to gather, transport or process our production. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely, and expect to rely in the future, on facilities developed and owned by third parties in order to store, process, transmit and sell our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil, gas and NGLs that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. If our access to markets for commodities we produce is restricted, our costs could increase and our expected production growth may be impaired.

If our assets become subject to FERC regulation or federal, state or local regulations or policies change, or if we fail to comply with market behavior rules, our financial condition, results of operations and cash flows could be materially and adversely affected.

Our gathering and transportation operations are exempt from regulation by the Federal Energy Regulatory Commission (“FERC”) FERC, under the Natural Gas Act (“NGA”). Section 1(b) of the NGA, exempts natural

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gas gathering facilities from regulation by the FERC under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC- regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts, or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act (“NGPA”). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale.

Moreover, FERC regulations indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and market center promotion, indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our results of operations and cash flows. The FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations in excess of $1 million per day for each violation and disgorgement of profits associated with any violation.

For more information regarding federal and state regulation of our operations, please read “Business—Regulation of Health, Safety and Environmental Matters.”

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation. In addition, potential future legislation may generally affect the taxation of natural gas and oil exploration and development companies, and may adversely affect our operations.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to natural gas and oil exploration and development companies. Such legislative proposals have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although no such provisions were included in the recently enacted 2017 budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act, no accurate prediction can be made as to whether any legislation will be proposed or enacted in the future that includes some or all of these proposals or, if enacted, what the specific provisions or the effective date of any such legislation would be. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows. Moreover, other more general features of tax reform legislation may be enacted that could change the taxation of natural gas and oil exploration and development companies. Future legislation could potentially adversely affect our business, operating results and financial condition.

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Furthermore, in California, there have been proposals for new taxes on oil and natural gas production. Although the proposals have not become law, campaigns by various interest groups could lead to future additional oil and natural gas severance or other taxes. The imposition of such taxes could significantly reduce our profit margins and cash flow and could ultimately result in lower oil and natural gas production, which may reduce our capital investments and growth plans.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to reduce the effect of risks associated with our business.

The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the over-the-counter (“OTC”) derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may enter and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations. At this time, the impact of such regulations is not clear.

Concerns about climate change and other air quality issues may affect our operations or results.

Concerns about climate change and regulation of GHGs and other air quality issues may materially affect our business in many ways, including by increasing the costs to provide our products and services, and reducing demand for, and consumption of, the oil and gas we produce. We may be unable to recover or pass through all or any of these costs. In addition, legislative and regulatory responses to such issues may increase our operating costs and render certain wells or projects uneconomic. To the extent financial markets view climate change and GHG emissions as a financial risk, this could adversely impact our cost of, and access to, capital. Both California and the United States Environmental Protection Agency (“EPA”) have adopted laws, and policies that seek to reduce GHG emissions as discussed in “Business—Regulation of Health, Safety and Environmental Matters—Climate Change” and “Business—Regulation of Health, Safety and Environmental Matters—California GHG Regulations.” Compliance with California cap and trade program laws and regulations could significantly increase our capital, compliance and operating costs and could also reduce demand for the oil and natural gas we produce. The cost to acquire GHG emissions allowances will depend on the market price for such instruments at the time they are purchased, the distribution of cost-free allowances among various industry sectors by the California Air Resources Board, and our ability to limit GHG emissions and implement cost-containment measures.

In addition, other current and proposed international agreements and federal and state laws, regulations and policies seek to restrict or reduce the use of petroleum products in transportation fuels and electricity generation, impose additional taxes and costs on producers and consumers of petroleum products, and require or subsidize the use of renewable energy.

Governmental authorities can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act (“CAA”) and associated state laws and regulations. In addition, California air quality laws and regulations, particularly in southern and central California where most of our operations are located, are in most instances more stringent than analogous federal laws and regulations.

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For example, the San Joaquin Valley will be required to adopt more rigorous attainment plans under the CAA to comply with federal ozone and particulate matter standards, and these efforts could affect our activities in the region.

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

We are not fully insured against all risks. Our oil and natural gas exploration and production activities, including well drilling, completion, stimulation, maintenance and abandonment activities, are subject to oil and natural gas operational risks such as fires, explosions, oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment, equipment failures and industrial accidents. Other catastrophic events such as earthquakes, floods, mudslides, fires, droughts, terrorist attacks and other events that cause operations to cease or be curtailed may adversely affect our business and the communities in which we operate. We may be unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented.

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

Similar to many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. We are also subject to litigation related to the Chapter 11 Proceeding. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of services of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

Information technology failures and cyber attacks could affect us significantly.

We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected.

In addition, as a producer of oil, natural gas and NGLS, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating

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costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cyber attacks on businesses have escalated in recent years and are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could lead to financial losses from remedial actions, loss of business or potential liability.

Risks Related to Emergence

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

The Chapter 11 Proceeding and our recent emergence from bankruptcy could adversely affect our business and relationships with customers, vendors, royalty and working interest owners, employees, service providers and suppliers. The following are among the risks associated with our emergence:

• vendors or other contract counterparties could terminate their relationship or require financial assurances or enhanced performance;

• our ability to renew existing contracts and compete for new business may be adversely affected; and

• our ability to attract, motivate and retain key executives and employees may be adversely affected.

Our financial condition or results of operations will not be comparable to the financial condition or results of operations reflected in our historical financial statements.

Since February 28, 2017, we have been operating under a new capital structure. In addition, we adopted fresh-start accounting and, as a result, at February 28, 2017 our assets and liabilities were recorded at fair value, which are materially different than amounts reflected in our historical financial statements. Accordingly, our financial condition and results of operations from and after the Effective Date will not be comparable to the financial condition or results of operations reflected in our historical financial statements included elsewhere in this prospectus. Further, as a result of the implementation of the Plan and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.

Due to our limited operating history as an independent company following our emergence from bankruptcy in February 2017, we have been in the process of establishing our accounting and other management systems and resources. We may be unable to effectively develop a mature system of internal controls, and a failure of our control systems to prevent error or fraud may materially harm our company.

Our predecessor company was an indirect, wholly-owned subsidiary of LINN Energy, and we utilized LINN Energy’s systems, software and personnel to prepare our financial information and to ensure that adequate internal controls over financial reporting were in place. Following our emergence from bankruptcy in February 2017, we assumed responsibility for these functions. In the course of transitioning these functions, we put in place a new executive management team and continue to add personnel, upgrade our systems, including information technology, and implement additional financial and managerial controls, reporting systems and procedures. These activities place significant demands on our management, administrative and operational resources, including accounting resources, and involve risks relating to our failure to manage this transition adequately.

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In addition, proper systems of internal controls over financial accounting and disclosure controls and procedures are critical to the operation of a public company. If we are unable to effectively develop a mature system of internal controls, we may be unable to reliably assimilate and compile financial information about our company, which would significantly impair our ability to prevent error, detect fraud or access capital markets.

A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Failure of our control systems to prevent error or fraud could materially adversely impact us.

Our limited operating history makes it difficult to evaluate our business plan and our long-term viability cannot be assured.

Our prospects for financial success are difficult to assess because we have a limited operating history since emergence from bankruptcy. There can be no assurance that our business will be successful, that we will be able to achieve or maintain a profitable operation, or that we will not encounter unforeseen difficulties that may deplete our capital resources more rapidly than anticipated. There can be no assurance that we will achieve or sustain profitability or positive cash flows from our operating activities.

Following our emergence from bankruptcy, we are under the management of a new board of directors.

Currently, our board of directors is made up of five directors, none of whom were involved in the management of our business prior to our bankruptcy. The new directors have different backgrounds, experiences and perspectives from those individuals who previously managed us and, thus, may have different views on our direction and the issues that will determine our future. The effect of implementation of those views may be difficult to predict and they may not lead us to achieve the goals we have set forth in this prospectus

Additionally, the ability of our new directors to quickly expand their knowledge of our operations, strategies and technologies will be critical to their ability to make informed decisions about our strategy and operations, particularly given the competitive environment in which our business operates. If our board of directors is not sufficiently informed to make these decisions, our ability to compete effectively and profitably could be adversely affected.

Two of our directors are also affiliated with entities holding a significant percentage of our stock. See “—There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.”

Risks Related to the Offering and our Capital Stock

There is currently no established public trading market for our outstanding common stock. Accordingly, the holders of our equity securities may have limited or no ability to sell their shares.

There is currently no established public trading market for our outstanding common stock, although our common stock has been quoted on the OTC Grey Market under the symbol “BRRP.” We cannot predict the extent to which investor interest in our company will lead to the development of a trading market on the            , or otherwise, or how active and liquid that market may become. The trading price on the            may bear no relation to the historical prices on the OTC Grey Market. There can be no assurance that a market for any of our equity securities will be established or that, if established, a market will be sustained. Therefore, holders of our equity securities may be unable to sell their shares.

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The market price of our equity securities could be subject to wide fluctuations in response to, and the level of trading that develops for our equity securities may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our limited trading history, our limited trading volume, the concentration of holdings of our equity securities, the lack of comparable historical financial information, in certain material respects, given the adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flows, the nature and content of our earnings releases, announcements or events that impact our assets, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this prospectus. No assurance can be given that an active market will develop for our equity securities or as to the liquidity of the trading market for our equity securities. If an active trading market does not develop or is not maintained, significant sales of our equity securities, or the expectation of these sales, could materially and adversely affect the market price of our equity securities.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

As of            , 2018, a majority of our outstanding common stock and our outstanding Series A Preferred Stock, which have voting rights identical to our common stock (with limited exceptions), was beneficially owned by a relatively small number of stockholders. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional equity or debt, that, in their judgment, could enhance their investment in Berry Corp. or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock or Series A Preferred Stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations.

Our significant stockholders and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in the Certificate of Incorporation could enable our significant stockholders to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents provide that our stockholders and their affiliates are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, the Amended and Restated Certificate of Incorporation of Berry Corp. filed with the Secretary of State of the State of Delaware (“the Certificate of Incorporation”), among other things:

• permits stockholders to make investments in competing businesses; and

• provides that if one of our directors who is also an employee, officer or director of a stockholder (a “Dual Role Person”) becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Our directors that are Dual Role Persons may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which our stockholders have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, our stockholders and their affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our waiving our interest and expectancy in any business opportunity that may be from time to time presented to any Dual Role Person could adversely impact our business or prospects if attractive business opportunities are procured by our stockholders for their own benefit rather than for ours.

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Certain of our stockholders and their affiliates have resources greater than ours, which may make it more difficult for us to compete with such persons with respect to commercial activities as well as for potential acquisitions. As a result, competition from certain stockholders and their affiliates could adversely impact our results of operations.

Investors in this offering will experience immediate and substantial dilution of $             per share.

Based on an assumed initial public offering price of $             per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $             per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2017 after giving effect to this offering would be $             per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

Future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or securities convertible into shares of our common stock. The Certificate of Incorporation provides that Berry Corp.’s authorized capital stock consists of 750,000,000 shares of common stock and 250,000,000 shares of preferred stock. After the completion of this offering, we will have                  outstanding shares of common stock. This number includes                 shares that we and the selling stockholders are selling in this offering and                  shares that we may sell in this offering if the underwriters’ over-allotment option is fully exercised. We have entered into the Registration Rights Agreement (as defined below) with certain of our stockholders, including the selling stockholders, pursuant to which such stockholders have the right, subject to various conditions and limitations, to demand the filing of a registration statement covering their shares of our common stock and to demand the Company to support underwritten sales of such shares, subject to the limitations specified in the Registration Rights Agreement. By exercising their registration rights and causing a large number of shares to be registered and sold in the public market, these holders could cause the price of our common stock to significantly decline. See “Description of Capital Stock—Registration Rights”

The issuance of any securities for acquisition, financing or other purposes, upon conversion or exercise of convertible securities, or otherwise may result in a reduction of the book value and market price of our outstanding common stock. If we issue any such additional securities, the issuance will cause a reduction in the proportionate ownership and voting power of all current stockholders. We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Shares of our common stock are reserved for issuance as equity-based awards to employees, directors and certain other persons under the 2017 Incentive Plan. In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 6,876,500 shares of our common stock issued or reserved for issuance under our 2017 Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction. Investors may experience dilution in the value of their investment upon the exercise of any equity awards that may be granted or issued pursuant to the 2017 Incentive Plan in the future.

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Our shares of Series A Preferred Stock are entitled to certain rights, privileges and preferences over our common stock.

Our Series A Preferred Stock ranks senior to our common stock with respect to dividend rights, redemption rights, sale, merger or change of control preference and rights on liquidation, dissolution and winding up of the affairs of Berry Corp. Holders of our Series A Preferred Stock are entitled to receive specified dividend payments, if we declare a dividend, and specified liquidating distributions, if we are liquidated, in each case in preference to holders of our common stock.

Additionally, our Series A Preferred Stock is convertible into shares of our common stock. The right to convert provides holders of our Series A Preferred Stock with an opportunity to profit from a rise in the market price of our common stock such that conversion of the Series A Preferred Stock could result in dilution of the equity interests of our common stockholders.

We are an “emerging growth company,” and will be able take advantage of reduced disclosure requirements applicable to “emerging growth companies,” which could make our common stock less attractive to investors.

We are an “emerging growth company” and, for as long as we continue to be an “emerging growth company,” we intend to take advantage of certain exemptions from various reporting requirements applicable to 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 our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We could be an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the first fiscal year in which our annual gross revenues exceed $1.07 billion, (ii) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common stock that is held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or (iii) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three year period.

“Emerging growth companies” can also delay adopting new or revised accounting standards until such time as those standards apply to private companies. We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act until we are no longer an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

We will incur significantly increased costs and devote substantial management time as a result of operating as a public company, particularly after we are no longer an “emerging growth company.”

As a public company, we will incur significant legal, accounting and other expenses. For example, we will be required to comply with applicable requirements of the Sarbanes-Oxley Act and the Dodd-Frank Act, as well as rules and regulations subsequently implemented by the SEC, including the establishment and maintenance of effective disclosure and financial controls and changes in corporate governance practices. Our management and other personnel will need to divert attention from operational and other business matters to devote substantial time to these public company requirements. In addition, after we no longer qualify as an “emerging growth

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company,” we expect to incur additional management time and cost to comply with the more stringent reporting requirements applicable to companies that are deemed accelerated filers or large accelerated filers, including complying with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act. We currently do not have an internal audit function, and we will need to hire or contract for additional accounting and financial staff with appropriate public company experience and technical accounting knowledge.

If we do not develop and implement all required financial reporting and disclosure procedures and controls, we may be unable to provide the financial information required of a U.S. publicly traded company in a timely and reliable manner.

Prior to this offering, we were not required to adopt or maintain all of the financial reporting and disclosure procedures and controls required of a U.S. publicly traded company because we were a privately held company. If we fail to develop and maintain effective internal controls and procedures and disclosure procedures and controls, we may be unable to provide financial information and required SEC reports that a U.S. publicly traded company is required to provide in a timely and reliable fashion. Any such delays or deficiencies could penalize us, including by limiting our ability to obtain financing, either in the public capital markets or from private sources and hurt our reputation and could thereby impede our ability to implement our growth strategy.

Our internal control over financial reporting is not currently required to meet the standards required by Section 404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act in the future could have a material adverse effect on our business and share price.

Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal control over financial reporting, starting with the second annual report that we file with the SEC after the consummation of our initial public offering, and generally requires a report by our independent registered public accounting firm on the effectiveness of our internal control over financial reporting. However, under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act until we are no longer an “emerging growth company,” which could be up to five years from now. Once we are no longer an “emerging growth company,” our independent registered public accounting firm may be required to attest to the effectiveness of our internal control over financial reporting on an annual basis. The rules governing the standards that must be met for our management to assess our internal control over financial reporting are complex and require significant documentation, testing and possible remediation.

In connection with the implementation of the necessary procedures and practices related to internal control over financial reporting, we may identify deficiencies that we may not be able to remediate in time to meet the deadline imposed by the Sarbanes-Oxley Act. In addition, we may encounter problems or delays in completing the implementation of any remediation of control deficiencies and receiving a favorable attestation in connection with the attestation provided by our independent registered public accounting firm. Furthermore, failure to achieve and maintain an effective internal control environment could have a material adverse effect on our business and share price and could limit our ability to report our financial results accurately and timely.

Certain provisions of the Certificate of Incorporation and Bylaws, as well as the Stockholders Agreement (as defined below), may make it difficult for stockholders to change the composition of our board of directors and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of the Certificate of Incorporation and the Amended and Restated Bylaws of Berry Corp. (the “Bylaws”) may have the effect of delaying or preventing changes in control if our board of directors determines that such changes in control are not in the best interests of Berry Corp. and our stockholders. For example, the Certificate of Incorporation and Bylaws include provisions that (i) authorize our board of directors to issue “blank check” preferred stock and to determine the price and other terms, including preferences and

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voting rights, of those shares without stockholder approval and (ii) establish advance notice procedures for nominating directors or presenting matters at stockholder meetings. Additionally, many of the largest holders of our equity securities are bound by the Stockholders Agreement, which requires them to vote their shares and take all other necessary actions to cause individuals designated by certain large stockholders to be elected to the board of directors until our third annual meeting of stockholders but not earlier than February 28, 2020.

These provisions could enable the board of directors to delay or prevent a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors, which is responsible for appointing the members of our management.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, all of our directors and executive officers, and the selling stockholders have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our common stock for a period of             days following the date of this prospectus.             , at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. See “Underwriting” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the common stock, subject to compliance with the Securities Act of 1933, as amended (the “Securities Act”) or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

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

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

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this prospectus includes “forward-looking statements.” All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, operating and financial projections, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

• volatility of oil, natural gas and NGL prices;

• inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures and meet working capital requirements;

• price and availability of natural gas;

• our ability to use derivative instruments to manage commodity price risk;

• impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

• uncertainties associated with estimating proved reserves and related future cash flows;

• our inability to replace our reserves through exploration and development activities;

• our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil and natural gas in commercially viable quantities;

• effects of competition;

• our ability to make acquisitions and successfully integrate any acquired businesses;

• market fluctuations in electricity prices and the cost of steam;

• asset impairments from commodity price declines;

• large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;

• geographical concentration of our operations;

• our ability to improve our financial results and profitability following our emergence from bankruptcy and other risks and uncertainties related to our emergence from bankruptcy;

• changes in tax laws;

• impact of derivatives legislation affecting our ability to hedge;

• ineffectiveness of internal controls;

• concerns about climate change and other air quality issues;

• catastrophic events;

• litigation;

• our ability to retain key members of our senior management and key technical employees;

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• information technology failures or cyber attacks; and

• other risks described in the section entitled “Risk Factors.”

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this prospectus. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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USE OF PROCEEDS

We expect to receive approximately $             million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We will not receive any proceeds from the sale of shares by the selling stockholders.

We intend to use the net proceeds we receive from this offering to repay outstanding borrowings under the RBL Facility and for general corporate purposes.

As of             , 2018, we had approximately $             million in borrowings outstanding under the RBL Facility, with a weighted average interest rate of approximately     %. Borrowings under the RBL Facility were primarily incurred to repay borrowings made under the Emergence Credit Facility (as defined below). Amounts repaid under the RBL Facility may be re-borrowed from time to time, subject to the terms of the facility, and we intend to do so from time to time for short-term liquidity and to fund periodic working capital shortfalls. The RBL Facility will mature on July 29, 2022.

A $1.00 increase or decrease in the assumed initial public offering price of $             per share (the midpoint of the price range set forth on the cover page of this prospectus) would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $             million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase due to a higher initial public offering price, we would use the additional net proceeds for general corporate purposes. If the proceeds decrease due to a lower initial public offering price, then we would first reduce by a corresponding amount the net proceeds directed to general corporate purposes and then, if necessary, the net proceeds directed to repay outstanding borrowings under our RBL Facility.

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DIVIDEND POLICY

We have not paid dividends on our Securities to date and do not anticipate paying cash dividends in the immediate future as we contemplate that our cash flows will be used for debt reduction and growth. Holders of Series A Preferred Stock are entitled to receive, when, as and if declared by our board of directors, cumulative dividends at a rate per share of 6.00% per annum of the Series A Accreted Value (as defined in the Series A Certificate of Designation), with such dividends compounding quarterly. On each March 31, June 30, September 30 and December 31 of each year, the amount of any dividends unpaid since the previous regular dividend payment date is added to the liquidation preference by increasing the Series A Accreted Value by any such unpaid dividends in accordance with the terms of the Series A Certificate of Designation. Initially, the Series A Accreted Value was $10.00 per share. Dividends may be paid, at our option, either in cash or in additional shares of Series A Preferred Stock, with such shares of Series A Preferred Stock having a deemed value of $10.00 per share.

The payment of future dividends, if any, will be determined by our board of directors in light of conditions then existing, including our earnings, financial condition, capital requirements, restrictions in financing agreements, business conditions and other factors. We are subject to certain restrictive covenants under the terms of the agreements governing our indebtedness that limit our ability to pay cash dividends.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of September 30, 2017:

• on an actual basis;

• on an as adjusted basis to give effect to the 2018 Notes Offering and the application of net proceeds therefrom; and

• on an as further adjusted basis to give effect to our sale of shares of our common stock in this offering at an assumed initial public offering price of $             per share (which is the midpoint of the range set forth on the cover of this prospectus) and the application of the net proceeds we receive from this offering as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with “Use of Proceeds”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus.

	As of September 30, 2017
	Actual		As Adjusted		As Further Adjusted (1)
	(in millions)
Cash and cash equivalents	$	3	$	16	$
Debt:
RBL Facility(2)	$	379	$	—	$
Senior Notes due 2026		—		400
Total debt		379		400
Stockholders’ Equity
Preferred Stock—$0.001 par value,              shares authorized and issued and outstanding, actual;             shares authorized and issued and outstanding, as adjusted; shares authorized and issued and outstanding, as further adjusted		335		335
Common Stock—$0.001 par value,             shares authorized and issued and outstanding, actual;             shares authorized and issued and outstanding, as adjusted; shares authorized and issued and outstanding, as further adjusted		543		543
Total stockholders’ equity		878		878
Total capitalization	$	1,257	$	1,278	$

(1) A $1.00 increase (decrease) in the assumed initial public offering price of $            per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $            million, $            million and $            million, respectively, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at an assumed offering price of $            per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $            million, $            million and $            million, respectively, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(2) As of            , the outstanding balance under the RBL Facility was approximately $            million, and we had cash and cash equivalents of approximately $            million.

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of September 30, 2017, was $             million, or $             per share.

Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering. Assuming an initial public offering price of $             per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of September 30, 2017 would have been approximately $             million, or $             per share. This represents an immediate increase in the net tangible book value of $             per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $             per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of September 30, 2017	$
Increase per share attributable to new investors in this offering
As adjusted pro forma net tangible book value per share after giving further effect to this offering
Dilution in pro forma net tangible book value per share to new investors in this offering		$

A $1.00 increase (decrease) in the assumed initial public offering price of $             per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $             and increase (decrease) the dilution to new investors in this offering by $             per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

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The following table summarizes, on an adjusted pro forma basis as of September 30, 2017, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at our initial public offering price of $             per share, calculated before deduction of estimated underwriting discounts and commissions:

	Shares Acquired				Total Consideration				Average Price Per Share
	Number	Percent			Amount	Percent
	(in thousands)
Existing stockholders(1)					$				$
New investors in this offering(2)
Total			100	%		$	100	%	$

(1) The number of shares disclosed for the existing stockholders includes shares being sold by the selling stockholders in this offering.

(2) The number of shares disclosed for the new investors does not include shares being purchased by the new investors from the selling stockholders in this offering.

The above tables and discussion are based on the number of shares of our common stock to be outstanding as of the closing of this offering (without exercise of the underwriters’ option to purchase additional shares). The table does not reflect shares of common stock reserved for issuance under our 2017 Incentive Plan.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table shows the selected historical financial information, for the periods and as of the dates indicated, of our predecessor company. The selected historical financial information as of and for the years ended December 31, 2015 and 2016 are derived from the audited historical consolidated financial statements of our predecessor company included elsewhere in this prospectus. The selected historical financial information as of and for the nine months ended September 30, 2016 and for the two months ended February 28, 2017 are derived from unaudited consolidated financial statements of our predecessor company included elsewhere in this prospectus. The summary historical financial information for the seven months ended September 30, 2017 is derived from unaudited consolidated financial statements of Berry Corp. included elsewhere in this prospectus.

Upon Berry LLC’s emergence from bankruptcy on February 28, 2017, or the Effective Date, in connection with the Plan, Berry LLC adopted fresh-start accounting and was recapitalized, which resulted in Berry LLC becoming a wholly-owned subsidiary of Berry Corp. and Berry Corp. being treated as the new entity for financial reporting. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. These fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our predecessor company’s historical consolidated balance sheet. The effects of the Plan and the application of fresh-start accounting are reflected in Berry Corp.’s consolidated financial statements as of the Effective Date and the related adjustments thereto are recorded in our consolidated statements of operations as reorganization items for the periods prior to the Effective Date. As a result, our consolidated financial statements subsequent to the Effective Date will not be comparable to our consolidated financial statements prior to such date. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material. You should read the following table in conjunction with “Use of Proceeds”, “Capitalization”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, the historical consolidated financial statements of our predecessor and accompanying notes included elsewhere in this prospectus.

	Berry Corp.			Berry LLC
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
										2016			2015
	(unaudited)			(unaudited)						(audited)			(audited)
							($ in thousands)
Statements of Operations Data:
Oil, natural gas and NGL liquid sales	$	237,324		$	74,120		$	285,538		$	392,345		$	575,031
Electricity sales		15,517			3,655			17,573			23,204			24,544
(Losses) gains on oil and natural gas derivatives		5,642			12,886			1,642			(15,781	)		29,175
Marketing revenues		1,901			633			2,743			3,653			5,709
Other revenues		3,902			1,424			5,634			7,570			7,195
Lease operating expenses		108,751			28,238			138,557			185,056			245,155
Electricity generation expenses		10,192			3,197			12,118			17,133			18,057
Transportation expenses		18,645			6,194			32,518			41,619			52,160
Marketing expenses		1,674			653			2,173			3,100			3,809
Taxes, other than income taxes		25,113			5,212			20,614			25,113			70,593
General and administrative expenses(1)		39,791			7,964			65,313			79,236			85,993
Reorganization items, net		(1,001	)		(507,720	)		(38,829	)		(72,662	)		—
Depreciation, depletion and amortization		48,392			28,149			139,980			178,223			251,371
Interest expense		(12,482	)		(8,245	)		(48,719	)		(61,268	)		(85,818	)

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	Berry Corp.			Berry LLC
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
										2016			2015
	(unaudited)			(unaudited)						(audited)			(audited)
	(in thousands except per share amounts)
Income tax (benefit) expense		9,190			230			196			116			(68	)
Net (loss) income		13,812			(502,964	)		(1,216,417	)		(1,283,196	)		(1,015,177	)
Net income per common share
Basic and Diluted	$	0.03			n/a			n/a			n/a			n/a
Weighted average common shares outstanding
Basic and Diluted		40,000			n/a			n/a			n/a			n/a
Cash Flow Data:
Net cash provided by (used in)
Operating activities	$	88,364		$	(30,176	)	$	3,269		$	12,345		$	122,518
Capital expenditures		(52,572	)		(3,158	)		(26,534	)		(34,796	)		(50,374	)
Acquisitions, sales of properties and other investing activities		(21,991	)		25			53,590			53,612			151,742
Balance Sheets Data:
(at period end)
Total assets	$	1,579,389		$	1,561,037		$	2,681,256		$	2,652,050		$	3,861,476
Current portion of long-term debt		—			—			891,259			891,259			873,175
Long-term debt, net		379,000			400,000			—			—			845,368
Series A Preferred Stock		335,000			335,000			—			—			—
Stockholders’ and/or member’s equity		877,541			862,827			569,741			502,963			1,786,159
Other Financial Data:
Adjusted EBITDA(2)	$	96,773		$	28,845		$	54,429		$	89,646		$	206,537
Adjusted General and Administrative Expenses(3)		11,468			7,964			65,313			79,236			85,993

(1) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $28.3 million for the seven months ended September 30, 2017.

(2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Prospectus Summary—Summary Historical and Pro Forma Financial Information—Non-GAAP Financial Measures.”

(3) Adjusted General and Administrative Expenses is a non-GAAP financial measure. For a definition of Adjusted General and Administrative Expenses and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Prospectus Summary—Summary Historical and Pro Forma Financial Information—Non-GAAP Financial Measures.”

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PRO FORMA FINANCIAL DATA

The following unaudited pro forma condensed consolidated financial information of Berry Corp. gives effect to the Company’s plan of reorganization and the Hugoton Disposition. Prior to the Effective Date, Berry Corp. had not conducted any business operations. Accordingly, these unaudited pro forma condensed consolidated financial statements are based on the historical financial statements of the Company’s wholly-owned subsidiary, Berry LLC. The unaudited pro forma condensed consolidated statements of operations are presented for the nine months ended September 30, 2017 and the year ended December 31, 2016. This unaudited pro forma condensed consolidated financial information should be read in conjunction with Berry Corp.’s historical financial statements for the seven months ended September 30, 2017 and with Berry LLC’s historical financial statements for the two months ended February 28, 2017, the nine months ended September 30, 2016, the year ended December 31, 2016 and the year ended December 31, 2015 included in this prospectus.

The unaudited pro forma statements of operations give effect to (1) the Plan and fresh-start accounting and (2) the Hugoton Disposition as if each had been completed as of January 1, 2016. The unaudited pro forma financial statements do not give effect to the Hill Acquisition because that transaction was not deemed significant under Rule 3-05 of the SEC’s Regulation S-X, so it is not required to be presented herein.

The unaudited pro forma condensed consolidated financial statements are for informational and illustrative purposes only and are not necessarily indicative of the financial results that would have been had the events and transactions occurred on the dates assumed, nor are such financial statements necessarily indicative of the results of operations in future periods. The unaudited pro forma condensed consolidated financial statements do not include realization of cost savings expected to result from the Plan. The pro forma adjustments, as described in the accompanying notes, are based upon currently available information. The historical financial information has been adjusted to give effect to pro forma adjustments that are (i) directly attributable to the Plan becoming effective or the Hugoton Disposition, (ii) factually supportable, and (iii) expected to have a continuing impact on the Company’s consolidated results.

Background

On May 11, 2016, the Linn Entities and Berry LLC filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in Bankruptcy Court. In December 2016, Berry LLC, on the one hand, and LINN Energy and its other affiliated debtors, on the other hand, filed separate plans of reorganization with the Bankruptcy Court. The Plan was filed on December 13, 2016. On January 27, 2017, the Bankruptcy Court entered its confirmation order approving and confirming the Plan.

In anticipation of the effectiveness of the Plan, Berry Corp. was formed for the purpose of having all the membership interests of Berry LLC assigned to it upon Berry LLC’s emergence from bankruptcy. On the Effective Date, the Plan became effective and was implemented in accordance with its terms. Among other transactions, 100% of Berry LLC’s outstanding membership interests were transferred to Berry Corp. As a result, Berry LLC emerged from bankruptcy as a wholly-owned subsidiary of Berry Corp., separate from LINN Energy and its affiliates.

Plan of Reorganization

On February 28, 2017, Berry LLC and Berry Corp. consummated the following reorganization transactions in accordance with the Plan:

1.    100% of the outstanding membership interests in Berry LLC were transferred to Berry Corp. pursuant to an assignment agreement. Under that assignment agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.

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2.    The holders of claims under Berry LLC’s Second Amended and Restated Credit Agreement, dated November 15, 2010, by and among Berry LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and certain lenders (as amended, the “Pre-Emergence Credit Facility”), received (i) their pro rata share of a cash paydown and (ii) pro rata participation in the Emergence Credit Facility (as defined below). As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.

3.    On the Effective Date, Berry LLC, as borrower, entered into a Credit Agreement, dated February 28, 2017, by and among Berry Corp., as parent guarantor, Wells Fargo Bank, N.A., as administrative agent, and certain lenders providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments (the “Emergence Credit Facility”).

4.    The holders of Berry LLC’s 6.75% senior notes due November 2020 and its 6.375% senior notes due September 2022 (together, the “Unsecured Notes”) received, through a rights offering, a right to their pro rata share of (i) either (a) 32,920,000 of shares of common stock in Berry Corp. or (b) for those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”) and (ii) specified rights to participate in a two-tranche offering of rights to purchase Series A Convertible Preferred Stock, par value $0.001 per share (the “Series A Preferred Stock”) at an aggregate purchase price of $335 million to fund the cash paydown of the Pre-Emergence Credit Facility. As a result, $335 million of Series A Preferred Stock was issued to certain of the holders of the Unsecured Notes that participated in the rights offering and all outstanding obligations under the Unsecured Notes, were canceled and the indentures and related agreements governing those obligations were terminated.

5.    The holders of unsecured claims against Berry LLC (other than the Unsecured Notes) (the “Unsecured Claims”) received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. As a result, all outstanding obligations under the Unsecured Notes and the indentures governing such obligations were canceled, and the obligations arising from the Unsecured Claims were extinguished.

6.    Berry LLC settled all intercompany claims against LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the confirmation order entered by the Bankruptcy Court. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy, which Berry LLC has fully reserved.

Fresh Start

Upon the Company’s emergence from bankruptcy, it was required to adopt fresh-start accounting, which, with the recapitalization described above, resulted in Berry Corp. being treated as the new entity for financial reporting purposes. The Company was required to adopt fresh-start accounting upon its emergence from bankruptcy because (i) the holders of existing voting ownership interests of our predecessor company received less than 50% of the voting shares of Berry Corp. and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims. An entity applying fresh-start accounting upon emergence from bankruptcy is viewed as a new reporting entity from an accounting perspective, and accordingly, may select new accounting policies.

The Plan and disclosure statement approved by the Bankruptcy Court did not include an enterprise value or reorganization value, nor did the Bankruptcy Court approve a value as part of its confirmation of the Plan. The Company must determine a value to be assigned to the equity of the emerging entity as of the date of adoption of fresh-start accounting. Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s long-term debt, stockholders’ equity and working capital. Reorganization value approximates the

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fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. Based on the various estimates and assumptions necessary for fresh-start accounting, the Company estimated its enterprise value as of the Effective Date to be approximately $1.3 billion. The enterprise value was estimated using a sum of the parts approach. The sum of parts approach represents the summation of the indicated fair value of the component assets of the Company. The fair value of the Company’s assets was estimated by relying on a combination of the income, market and cost approaches.

The reorganization value was allocated to the Company’s individual assets generally based on their estimated fair values. For purposes of the accompanying unaudited pro forma condensed consolidated statements of operations, the Company utilized its estimated enterprise value as of the Effective Date, and applied such enterprise value as of January 1, 2016. Preparation of an actual valuation with assumptions and economic data as of January 1, 2016 would likely result in an enterprise value that is materially different than such valuation as of the Effective Date. The intent of the unaudited pro forma condensed consolidated financial statements is to illustrate the effects of the Plan based on the underlying economic factors as of the Effective Date.

Hugoton Disposition

The Company closed on the sale of its interests in the Hugoton natural gas field, located primarily in Kansas, effective July 31, 2017. See “Prospectus Summary—Recent Developments—Hill Acquisition and Hugoton Disposition” for additional information.

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BERRY PETROLEUM CORPORATION

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017

(in thousands)

	Berry LLC (Predecessor)			Berry Corp. (Successor)			Fresh-Start Accounting Adjustments			Hugoton Disposition Adjustments			Berry Corp. (Successor) Pro Forma
	Two Months Ended February 28, 2017			Seven Months Ended September 30, 2017
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	74,120		$	237,324		$	—		$	(37,842	)(g)	$	273,602
Electricity sales		3,655			15,517			—			—			19,172
Gains on oil and natural gas derivatives		12,886			5,642			—			—			18,528
Marketing revenues		633			1,901			—			—			2,534
Other revenues		1,424			3,902			—			(5,265	)(g)		61
		92,718			264,286			—			(43,107	)		313,897
Expenses:
Lease operating expenses		28,238			108,751			—			(6,129	)(h)		130,860
Electricity generation expenses		3,197			10,192			—			—			13,389
Transportation expenses		6,194			18,645			—			(10,007	)(h)		14,832
Marketing expenses		653			1,674			—			—			2,327
General and administrative expenses		7,964			39,791			—			(1,292	)(h)		46,463
Depreciation, depletion and amortization.		28,149			48,392			(14,105	)(b)		(6,685	)(i)		55,751
Taxes, other than income taxes		5,212			25,113			—			(4,868	)(h)		25,457
Gains on sale of assets and other, net		(183	)		(20,687	)		—			20,688	(j)		(182	)
		79,424			231,871			(14,105	)		(8,293	)		288,897
Other income and (expenses):
Interest expense, net of amounts capitalized		(8,245	)		(12,482	)		4,930	(d)		—			(15,797	)
Other, net		(63	)		4,070			—			—			4,007
		(8,308	)		(8,412	)		4,930			—			(11,790	)
Reorganization items, net		(507,720	)		(1,001	)		507,720	(e)		—			(1,001	)
(Loss) income before income taxes		(502,734	)		23,002			526,755			(34,814	)		12,209
Income tax expense (benefit)		230			9,190			7,616			(12,165	)(f)		4,871
Net income (loss)		(502,964	)		13,812			519,139			(22,649	)		7,338

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BERRY PETROLEUM CORPORATION

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2016

(in thousands)

	Berry LLC (Predecessor)
	Year ended December 31, 2016			Fresh-Start Accounting Adjustments			Hugoton Disposition Adjustments			Berry Corp. (Successor) Pro Forma
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	392,345		$	—			(49,176	)(g)	$	343,169
Electricity sales		23,204			—			—			23,204
Losses on oil and natural gas derivatives		(15,781	)		—			—			(15,781	)
Marketing revenues		3,653			—			—			3,653
Other revenues		7,570			—			(7,247	)		323
		410,991			—			(56,423	)		354,568
Expenses:
Lease operating expenses		185,056			—			(8,387	)(h)		176,669
Electricity generation expenses		17,133			—			—			17,133
Transportation expenses		41,619			—			(15,676	)(h)		25,943
Marketing expenses		3,100			—			—			3,100
General and administrative expenses		79,236			(1,249	)(a)		(275	)(h)		77,712
Depreciation, depletion and amortization		178,223			(93,956	)(b)		(22,753	)(i)		61,514
Impairment of long-lived assets		1,030,588			—	(c)		—			1,030,588
Taxes, other than income taxes		25,113			—			(2,775	)(h)		22,338
Gains on sale of assets and other, net		(109	)		—			—			(109	)
		1,559,959			(95,205	)		(49,866	)		1,414,888
Other income and (expenses):
Interest expense, net of amounts capitalized		(61,268	)		41,040	(d)		—			(20,228	)
Other, net		(182	)		—			—			(182	)
		(61,450	)		41,040			—			(20,410	)
Reorganization items, net		(72,662	)		72,662	(e)		—			—
Loss before income taxes		(1,283,080	)		208,907			(6,557	)		(1,080,730	)
Income tax expense		116			—	(f)		—	(f)		116
Net income (loss)	$	(1,283,196	)		208,907			(6,557	)	$	(1,080,846	)

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BERRY PETROLEUM CORPORATION

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

1.    Basis of Presentation

The accompanying unaudited pro forma condensed consolidated statements of operations and explanatory notes present the financial information of Berry Corp. assuming the events and transactions had occurred on January 1, 2016.

The following are descriptions of the columns included in the accompanying unaudited pro forma condensed consolidated statements of operations:

Predecessor represents the historical condensed consolidated statements of operations of Berry LLC for the year ended December 31, 2016 and for the two months ended February 28, 2017.

Successor represents the historical condensed consolidated statements of operations of Berry Corp. for the seven months ended September 30, 2017.

Fresh-Start Accounting Adjustments represent adjustments to give effect to the Plan and fresh-start accounting to the condensed consolidated statements of operations as of the date assumed.

Hugoton Disposition Adjustments represent adjustments to give effect to the disposition of the Company’s interests in the Hugoton basin natural gas fields to the condensed consolidated statements of operations as of the date assumed.

2.    Pro Forma Adjustments

Fresh-Start Accounting Adjustments

The adjustments included in the unaudited pro forma consolidated statements of operations above reflect the effects of the transactions contemplated by the Plan and executed by the Company on the Effective Date as well as fair value and other required accounting adjustments resulting from the adoption of fresh-start accounting.

(a)    Reflects the elimination of legal and professional fees related to debt restructuring and bankruptcy advisors that were incurred prior to the bankruptcy petition date and are not classified as reorganization items. These fees are nonrecurring expenses that are incremental to the Company’s continuing operations.

(b)    Reflects a reduction of depreciation, depletion and amortization expense based on new asset values and useful lives as a result of adopting fresh-start accounting as of the Effective Date.

(c)    During 2016, the Company recorded impairment charges associated with (a) proved oil and natural gas properties of approximately $1.0 billion and (b) unproved properties of approximately $13 million. Assuming the emergence from bankruptcy occurred on January 1, 2016, and the adjustment of oil and natural gas properties to the estimated fair value as a result of fresh-start accounting had been recorded, there would likely be no impairment in 2016. However, no pro forma adjustment was made as the impairment charge would have no continuing impact on the Company’s consolidated results.

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(d)    As of the Effective Date, borrowings under the Emergence Credit Facility of $400 million were outstanding, which had an interest rate of 4.81% per annum, letter of credit fees at a rate of 3.75% per annum and a 0.50% per annum commitment fee on undrawn amounts. In addition, issuance costs were being amortized over the five year term of the Emergence Credit Facility. The Company calculated the pro forma adjustment to decrease interest expense as follows:

For the two months ended February 28, 2017:

	(in thousands)
Reversal of Pre-Emergence Credit Facility interest expense	$	7,789
Reversal of amortization of issuance costs on Pre-Emergence Credit Facility		416
Reversal of other interest expense		40
Pro forma – Emergence Credit Facility interest expense on drawn amounts		(3,153	)
Pro forma – Emergence Credit Facility commitment fee on undrawn amounts		(118	)
Pro forma – Emergence Credit Facility letter of credit fees		(39	)
Pro forma – Amortization of issuance costs on the Emergence Credit Facility		(5	)
Pro forma adjustment to decrease interest expense for the two months ended February 28, 2017	$	4,930

For the year ended December 31, 2016:

	(in thousands)
Reversal of Pre-Emergence Credit Facility interest expense	$	40,683
Reversal of Unsecured Notes interest expense		19,166
Reversal of amortization of issuance costs on Pre-Emergence Credit Facility		2,495
Reversal of other interest expense related to Pre-Emergence Credit Facility and Unsecured Notes		250
Reversal of capitalized interest		(1,325	)
Pro forma – Emergence Credit Facility interest expense on drawn amounts		(19,240	)
Pro forma – Emergence Credit Facility commitment fee on undrawn amounts		(718	)
Pro forma – Emergence Credit Facility letter of credit fees		(241	)
Pro forma – Amortization of issuance costs on the Emergence Credit Facility		(30	)
Pro forma adjustment to decrease interest expense for the year ended December 31, 2016	$	41,040

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(e)    Represents the elimination of reorganization items that were directly attributable to the Chapter 11 reorganization and nonrecurring costs directly related to the bankruptcy, which consist of the following:

For the two months ended February 28, 2017:

	(in thousands)
Gain on settlement of liabilities subject to compromise	$	(437,474	)
Fresh-start valuation adjustments		920,699
Legal and other professional advisory fees		19,481
Other		5,014
Pro forma adjustment to eliminate reorganization items for the two months ended February 28, 2017	$	507,720

For the year ended December 31, 2016:

	(in thousands)
Legal and other professional advisory fees	$	30,130
Unamortized premiums		(10,923	)
Terminated contracts		55,148
Other		(1,693	)
Pro forma adjustment to eliminate reorganization items for the year ended December 31, 2016	$	72,662

In connection with our emergence from bankruptcy, we terminated or renegotiated more favorable terms for several firm transportation and oil sales contracts.

(f)    Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC, which had been treated as a disregarded entity for federal and state income taxes, in a taxable asset acquisition as part of the restructuring. For the nine month period ended September 30, 2016 and for the year ended December 31, 2016, any tax benefit that would potentially be realizable as a result of the new tax status and losses incurred during the year have not been recognized, under the assumption that the Company would not meet the “more likely than not” criteria under Accounting Standards Codification 740 “Income Taxes” and therefore would require a full valuation allowance.

For the nine months ended September 30, 2017, the effective tax rate used to calculate income tax expense was 39.9%. The effective tax rate differed from the federal statutory rate of 35% due to the impact of state taxes.

Hugoton Disposition Adjustments

(g)    Reflects the elimination of oil, natural gas, natural gas liquids and helium gas sales related to the Hugoton Disposition properties.

(h)    Reflects the adjustments related to lease operating, transportation, taxes other than income taxes and general and administrative expenses related to the Hugoton Disposition properties.

(i)    Reflects the elimination of estimated depreciation, depletion and amortization as well as accretion expense related to the Hugoton Disposition properties.

(j)    Reflects the elimination of the gain on sale of assets related to the Hugoton Disposition.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are described under the heading “Risk Factors” included elsewhere in this prospectus. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Please see “Cautionary Note Regarding Forward-Looking Statements.” When we use the terms “we,” “us,” “our,” the “Company,” or similar words in this prospectus, unless the context otherwise requires, on or prior to the Effective Date, we are referring to Berry LLC, and following the Effective Date, we are referring to Berry Corp. and its subsidiary, Berry LLC, as applicable. When we refer to “our predecessor company” we are referring to Berry LLC on or prior to the Effective Date.

Our Company

We are a value-driven, independent oil and natural gas company engaged primarily in the development and production of conventional reserves located in the western United States, including California, Utah, Colorado and Texas. We target onshore, low-cost, low-risk, oil-rich basins, such as the San Joaquin basin of California and the Uinta basin of Utah. The Company’s assets are characterized by:

• high oil content with production consisting of approximately 82% oil;

• long-lived reserves with low and predictable production decline rates;

• an extensive inventory of low-risk development drilling opportunities with attractive full-cycle economics;

• a stable and predictable development and production cost structure; and

• favorable Brent-influenced crude oil pricing dynamics.

Our asset base is concentrated in the San Joaquin basin in California, which has over 100 years of production history and substantial remaining original oil in place. We focus on conventional, shallow reservoirs, the drilling and completion of which are low-cost in contrast to modern unconventional resource plays. Our decades-old proven completion techniques include steamflood and low-volume fracture stimulation.

We focus on enhancing our production, improving drilling and completion techniques, controlling costs and maximizing the ultimate recovery of hydrocarbons from our assets, with the goal of generating top-tier returns. We seek to fund repeatable organic production and reserves growth through the use of internally generated free cash flow from operations after debt service, or levered free cash flow, while also maintaining ample liquidity and a conservative financial leverage profile.

As of November 30, 2017, we had estimated proved reserves of 141,838 MBoe, of which approximately 57% were proved developed producing reserves and approximately 66% of total proved reserves were located in California. For the three months ended September 30, 2017, pro forma for the Hugoton Disposition and the Hill Acquisition, we had average production of approximately 27.0 MBoe/d, of which approximately 82% was oil.

Chapter 11 Bankruptcy and Our Emergence

In 2013, the Linn Entities acquired our predecessor company for LinnCo LLC shares and assumed debt with an aggregate value of $4.6 billion. A severe industry downturn, coupled with high leverage and significant fixed charges, led the Linn Entities and, consequently, our predecessor company to initiate the Chapter 11 Proceeding on May 11, 2016.

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On February 28, 2017, Berry LLC emerged from bankruptcy as a stand-alone company and wholly-owned subsidiary of Berry Corp. with new management, a new board of directors and new ownership. Through the Chapter 11 Proceeding, the Company significantly improved its financial position from that of Berry LLC while it was owned by the Linn Entities. These improvements included:

• the elimination of approximately $1.3 billion of debt and more than $76 million of annualized interest expense;

• the termination of, or renegotiation of more favorable terms for, several firm transportation and oil sales contracts; and

• the anticipated reduction in recurring general and administrative costs as a stand-alone company by following a lean operating model.

On the February 28, 2017, Berry LLC and Berry Corp. consummated the following reorganization transactions in accordance with the Plan:

• 100% of the outstanding membership interests in Berry LLC were transferred to Berry Corp. pursuant to an assignment agreement. Under that assignment agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.

• The holders of claims under Pre-Emergence Credit Facility, received (i) their pro rata share of a cash paydown and (ii) pro rata participation in the Emergence Credit Facility. As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.

• On the Effective Date, Berry LLC entered into the Emergence Credit Facility.

• The holders of Berry LLC’s Unsecured Notes received, through a rights offering, a right to their pro rata share of (i) either (a) 32,920,000 of shares of common stock in Berry Corp. or (b) for those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool and (ii) specified rights to participate in a two-tranche offering of rights to purchase the Series A Preferred Stock at an aggregate purchase price of $335 million to fund the cash paydown of the Pre-Emergence Credit Facility. As a result, $335 million of Series A Preferred Stock was issued to certain of the holders of the Unsecured Notes that participated in the rights offering and all outstanding obligations under the Unsecured Notes, were canceled and the indentures and related agreements governing those obligations were terminated.

• The holders of the Unsecured Claims received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. As a result, all outstanding obligations under the Unsecured Notes and the indentures governing such obligations were canceled, and the obligations arising from the Unsecured Claims were extinguished.

• Berry LLC settled all intercompany claims against LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the confirmation order entered by the Bankruptcy Court. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy, which Berry LLC has fully reserved.

Preferred Stock

The Series A Preferred Stock ranks senior to each other series or class of capital stock of Berry Corp. with respect to dividend rights, redemption rights, sale, merger or change of control preference and rights on liquidation, dissolution and winding up of the affairs of Berry Corp. Holders of Series A Preferred Stock are entitled to receive, when, as and if declared by the board of directors, cumulative dividends at a rate of 6.00% per annum either in cash or in additional shares of Series A Preferred Stock at the discretion of the board of directors. The Series A Preferred Stock is entitled to vote with holders of common stock, voting together as a single class, with respect to any and all

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matters subject to a stockholder vote, other than as required by law. If Berry Corp. liquidates, dissolves or winds up, holders of Series A Preferred Stock, in preference to any other series or class of capital stock of Berry Corp., will be entitled to share ratably in Berry Corp.’s assets that are legally available for distribution to Berry Corp.’s stockholders, after payment of its debts and other liabilities, in an amount per share of Series A Preferred Stock equal to the sum of (i) $10.00 plus (ii) any accrued and unpaid regular dividends. The Series A Preferred Stock may be converted into a number of shares of common stock determined by the applicable Conversion Rate (as defined in the Series A Preferred Stock Certificate of Designation (the “Certificate of Designation”)) (i) at the option of the holder at any time and (ii) at our option at any time after February 28, 2021, subject to certain conditions, including that the value of a share of common stock into which a share of Series A Preferred Stock is convertible is equal to or greater than $15.00, based on the volume-weighted average price for any 20-trading day period during the 30 trading days preceding conversion. From the time at which any shares of Series A Preferred Stock are deemed to have been converted, the holder of such converted shares shall no longer be entitled to receive dividends on such Series A Preferred Stock (including any prior accrued or unpaid dividend). The Series A Preferred Stock is not subject to redemption by us or at the option of any holder of Series A Preferred Stock and is not entitled to a retirement or sinking fund. The Certificate of Designation contains no financial or operational covenants restricting our activities or our ability to raise capital.

How We Evaluate Operations

Our management team uses the following metrics to manage and assess the performance of our operations: (a) production, (b) operating expenses, (c) environmental, health & safety (“EH&S”), (d) taxes, other than income taxes, (e) general and administrative expenses, (f) Adjusted EBITDA and (g) levered free cash flow.

Production

Oil and gas production is a key driver of our operating performance, an important factor to the success of our business, and used in forecasting future development economics. We measure and closely monitor production on a continuous basis, adjusting our property development efforts in accordance with the results. We track production by commodity type and compare it to prior periods and expected results.

Operating expenses

We define operating expenses as lease operating expenses, electricity expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity and marketing activities. The electricity and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economics of development projects and the efficiency of our hydrocarbon recovery. Overall, operating expenses is used by management as a measure of the efficiency with which operations are performing.

Environmental, health & safety

We are committed to good corporate citizenship in our communities, operating safely and protecting the environment and our employees. We monitor our EH&S performance through various measures, holding our employees and contractors to high standards. Meeting corporate EH&S metrics is a part of our incentive programs for all employees.

Taxes, other than income taxes

Taxes, other than income taxes includes severance taxes, ad valorem and property taxes, GHG allowances, and other taxes. We include these taxes when analyzing the economics of development projects and the efficiency of our hydrocarbon recovery; however, these taxes are not included in our operating expenses.

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General and administrative expenses

We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities. Such expenses are a key component of the appropriate level of support our corporate and professional team provides to the development of our assets and our day-to-day operations.

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business. We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, amortization and accretion; exploration expense; derivative gains or losses net of cash received for derivative settlements; impairments; stock compensation expense and other unusual out-of-period and infrequent items, including restructuring and reorganization costs.

Levered free cash flow

Levered free cash flow reflects our financial flexibility and is used to plan our internal growth capital expenditures. We define levered free cash flow as Adjusted EBITDA less capital expenditures, asset retirement obligation expenditures, interest expense, reorganization/transition costs, and other expenses. Levered free cash flow is our primary metric used in planning capital allocation for maintenance and internal growth opportunities as well as hedging needs and serves as a measure for assessing our financial performance and measuring our ability to generate excess cash from our operations after servicing indebtedness.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Basis of Presentation and Fresh-Start Accounting

Upon Berry LLC’s emergence, we adopted fresh-start accounting, which, with the recapitalization described above, resulted in Berry Corp. becoming the financial reporting entity in its corporate group. Unless otherwise noted or suggested by context, all financial information and data and accompanying financial statements and corresponding notes, as contained in this prospectus, on or prior to the Effective Date, reflect the actual historical results of operations and financial condition our predecessor company for the periods presented and do not give effect to the Plan or any of the transactions contemplated thereby or the adoption of fresh-start accounting. Following the Effective Date, they reflect the actual historical results of operations and financial condition of Berry Corp. on a consolidated basis and give effect to the Plan and any of the transactions contemplated thereby and the adoption of fresh-start accounting. Thus, the financial information presented herein on or prior to the Effective Date may not be comparable to Berry Corp.’s performance or financial condition after the Effective Date. As a result, “black-line” financial statements are presented to distinguish between Berry LLC as the predecessor and Berry Corp. as the successor.

Berry Corp.’s financial statements reflect the application of fresh-start accounting under GAAP. GAAP requires that the financial statements, for periods subsequent to the Chapter 11 Proceeding, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on Berry Corp.’s as well as Berry LLC’s statements of operations. In addition, Berry Corp.’s balance sheet classifies the cash distributions from the Cash Distribution Pool as “liabilities subject to compromise.” Prepetition unsecured and under-secured obligations that were impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on our predecessor company’s last audited balance sheet at December 31, 2016.

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Reorganization and Financing Activities

Through the Chapter 11 Proceeding and reorganization transactions described above under “—Chapter 11 Bankruptcy and Our Emergence,” we were able to significantly improve our financial position by eliminating approximately $1.3 billion of debt and more than $76 million of annualized interest expense. We have experienced a reduction that we expect to continue in recurring general and administrative costs as a stand-alone company separate from LINN Energy, which will significantly impact comparability of periods before the Effective Date with periods on and after the Effective Date. In addition to the notes offering contemplated in this prospectus, we have also completed the following financing activities post-emergence.

New RBL Facility

On July 31, 2017, Berry LLC, as borrower, entered into a Credit Agreement with Berry Corp., as parent guarantor, Wells Fargo Bank, N.A., as administrative agent and issuing lender, and certain lenders. The credit facility established pursuant to the Credit Agreement and related agreements is referred to in this prospectus as the “RBL Facility.” The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments, with a borrowing base of $             million and approximately $             million of undrawn availability as of                , 2018. The RBL Facility also provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the RBL Facility on a dollar for dollar basis. As of September 30, 2017, Berry LLC had $379 million in borrowings and $21 million in letters of credit outstanding under the RBL Facility. For additional information, please read “—Liquidity and Capital Resources—Debt—New RBL Facility”.

Hill Acquisition and Hugoton Disposition

On July 31, 2017, we completed the Hugoton Disposition and the Hill Acquisition. These transactions significantly increased the percentage of our production that is oil, which benefits from California pricing margins, increased our future drilling opportunities, concentrated our assets and were essentially operating cash flow neutral at the time of the transactions. With the Hill Acquisition, we gained the remaining working interest in approximately 1,100 identified gross drilling locations. We used the proceeds of the Hugoton Disposition and cash on hand to complete the Hill Acquisition.

The table below compares certain aspects of the Hill Acquisition and the Hugoton Disposition:

	Hill Acquisition		Hugoton Disposition
Estimated PV-10 (millions)(1)(2)	$	290	$	190
Proved Reserves (MMBoe)(1)		24.7		62.6
Average Net Daily Production from January 1, 2017 – September 30, 2017(Boe/d)		3,000		9,533
Revenue Equivalent Barrels of oil per day from January 1, 2017 – September 30, 2017(1)(3)				3,650
Percent (%) product mix (Oil/Natural Gas Equivalent/NGLs for January 1, 2017 – September 30, 2017)		100 / 0 / 0		0 / 66 / 34

(1) We estimated reserve volumes and the PV-10 value of the Hugoton asset as of March 31, 2017 in accordance with SEC guidance. Reserve volumes and the PV-10 value of the Hill asset represents the value associated with the 84% non-operated working interest acquired in the Hill Acquisition and does not include the value associated with the 16% operated working interest already owned. We estimated reserve volumes of the Hill asset as of March 31, 2017 in accordance with SEC guidance. Primarily as a result of an increase in oil prices, the PV-10 value of the Hill asset has increased significantly since the completion of the Hill Acquisition. The PV-10 value in the table above is as of November 30, 2017. As of March 31, 2017, the PV-10 value of the Hill asset was approximately $216 million.

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(2) PV-10 is a non-GAAP financial measure. For a definition of PV-10, please read “Prospectus Summary—Summary Reserves and Operating Data—PV-10.” PV-10 does not give effect to derivatives transactions.

(3) Because the Hugoton asset produced primarily natural gas and the Hill asset produces oil, revenue from the sale of 9,533 Boe/d from the Hugoton asset would be equal to revenue generated from the sale of 3,650 Boe/d at the Hill asset.

Senior Unsecured Notes Offering

In February 2018, we closed the 2018 Notes Offering of $400 million principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $392 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the 2018 Notes Offering to repay borrowings under the RBL Facility and will use the remainder for general corporate purposes.

Capital Expenditures and Capital Budget

For the years ended December 31, 2016 and 2015, our capital expenditures were approximately $26 million and $152 million, respectively, on an accrual basis including amounts paid by Linn Energy and excluding acquisitions. Beginning in 2015 and carrying forward until the commencement of the Chapter 11 Proceeding in May 2016, attempting to decrease our predecessor company’s level of indebtedness and maintain its liquidity at levels sufficient to meet its commitments, LINN Energy and our predecessor company undertook a number of actions, including minimizing capital expenditures and further reducing recurring operating expenses. Despite taking these actions, LINN Energy did not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations and comply with its debt covenants and commenced the Chapter 11 Proceeding. Prior to the Effective Date, our predecessor company had financed its drilling and development program primarily through internally generated net cash provided by operating activities and funding from LINN Energy. Following commencement of the Chapter 11 Proceeding, our predecessor company halted substantially all of its planned capital expenditures until the Effective Date.

For the nine months ended September 30, 2017, we invested approximately $59 million in capital expenditures. Following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities, we increased our pace of development and expect to continue to do so in 2018. Our 2018 anticipated capital expenditure budget of approximately $135 to $145 million represents an increase of approximately 84% over our expected 2017 capital expenditures of approximately $74 to $78 million. Based on current commodity prices and a drilling success rate comparable to our historical performance, we believe we will be able to fund our 2018 capital program with our levered free cash flow. We expect to:

• employ:

• two drilling rigs in California continuously through 2018; and

• one additional drilling rig assigned to certain projects in the second half of 2018;

• drill approximately 180 to 190 gross development wells, of which we expect at least 175 will be in California; and

• maintain a fairly constant pace of drilling throughout the year.

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The table below sets forth by basin the allocation of our expected 2017 capital expenditures and the expected allocation of our 2018 capital expenditure budget assuming total capital expenditures of $140 million, the midpoint of the range of our estimated capital expenditures for 2018.

	Capital Expenditure by Area
	2018 Budget		2017 Expected
	(in millions)
California	$	113	$	74
Uinta		9		1
Piceance		12		1
East Texas		—		—
Corporate		6		—
Total	$	140	$	76

The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial condition and results of operations.

Commodity Derivatives

Historically, we have utilized swap contracts, collars and three-way collars to hedge a portion of our forecasted production and reduce exposure to fluctuations in oil and natural gas prices. Swap contracts are designed to provide a fixed price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. From time to time, we have also entered into derivative contracts for a portion of our natural gas consumption. We do not enter into derivative contracts for speculative trading purposes. We continuously consider the level of our production that is appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity prices, our overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of hedging contained in any credit facility or other debt instrument applicable at the time. Currently, our hedging program mainly consists of swaps.

Our open positions as of September 30, 2017 were as follows:

	2017		2018		2019		2020
Sold NYMEX WTI call options:
Hedged volume (MBbls)		150		900		840		390
Weighted average price ($/Bbl)	$	55.00	$	55.00	$	57.32	$	60.00
Oil positions:
Fixed Price Swaps (NYMEX WTI)
Hedged volume (MBbls)		1,335		4,817		4,197		—
Weighted average price ($/Bbl)	$	52.54	$	52.04	$	52.05		—
Oil basis differential positions:
ICE Brent – NYMEX WTI basis swaps
Hedged volumes (MBbls)		552		1,460		1,095		—
Weighted average price ($/Bbl)	$	1.24	$	1.21	$	1.17		—

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The following table summarizes the historical results of our hedging activities.

	Berry Corp. (Successor)		Berry LLC (Predecessor)
	Seven Months Ended   September 30,   2017		Two Months Ended February 28, 2017
Crude Oil (per Bbl):
Realized price, before the effects of derivative settlements	$	44.86	$	46.94
Effects of derivative settlements	$	1.44	$	0.25

In May 2016 and July 2016, as a result of the Chapter 11 Proceeding, our predecessor company’s counterparties canceled (prior to the contract settlement dates) all of our predecessor company’s then-outstanding derivative contracts and our predecessor company received net cash proceeds of approximately $2 million. The net cash proceeds received were used to make permanent repayments of a portion of the borrowings outstanding under the Pre-Emergence Credit Facility. In December 2016, our predecessor company entered into commodity derivative contracts consisting of oil swaps for January 2017 through December 2019. In February 2017, our predecessor company entered into commodity derivative contracts consisting of WTI/Brent basis swaps for March 2017 through December 2019. In July 2017, Berry Corp. entered into commodity derivative contracts consisting of oil swaps and oil options for July 2017 through June 2020. In October 2017, Berry Corp. entered into commodity derivatives contracts consisting of oil swaps for January 2018 through June 2018.

We expect our operations to generate substantial cash flows at current commodity prices. We have protected a portion of our anticipated cash flows through 2020 as part of our crude oil hedging program. Our low-decline production base, coupled with our stable operating cost environment, affords us the ability to hedge a material amount of our future expected production. As of January 4, 2018, we have hedged approximately 6.4 MMBbls for 2018, 5.0 MMBbls for 2019 and 0.4 MMBbls for 2020 of crude oil production.

Income Taxes

Prior to the Effective Date, Berry LLC was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of Berry LLC. Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC in a taxable asset acquisition as part of the restructuring. Consequently, we are now taxed as a corporation and have no pre-2017 net operating loss carryforwards.

Business Environment and Market Conditions

The oil and gas industry is heavily influenced by commodity prices. Since the latter half of 2014, commodity prices declined and remained at relatively low levels through of the beginning of 2017, but have generally risen since then. For example, the Brent spot price for oil declined from a high of over $115.06 per Bbl on June 19, 2014 to a low of $27.88 per Bbl on January 20, 2016, and the Henry Hub spot price for natural gas declined from a high of $6.15 per MMBtu on February 19, 2014 to a low of $1.64 per MMBtu on March 3, 2016. While prices remain lower than the 2014 averages, they have improved since early 2016. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production. Please see “Risk Factors—Risks Related to Our Business and Industry—Oil, natural gas and NGL prices are volatile.”

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The following table presents the average ICE (Brent) oil, NYMEX (WTI) oil and NYMEX Henry Hub natural gas prices for the nine months ended September 30, 2017, and the years ended December 31, 2016 and 2015:

	Nine Months Ended September 30, 2017		Year Ended December 31,
			2016		2015
ICE (Brent) oil ($/Bbl)	$	52.59	$	45.00	$	53.64
NYMEX (WTI) oil ($/Bbl)	$	49.47	$	43.32	$	48.80
NYMEX Henry Hub natural gas ($/MMBtu)	$	3.17	$	2.46	$	2.66

Oil prices and differentials will continue to be affected by a variety of factors, including worldwide and regional economic conditions, transportation costs, imports, political conditions in producing regions, exploration levels, inventory levels, the actions of OPEC and other state-controlled oil companies and significant producers, local pricing, gathering facility and transportation dynamics, exploration, development, production and transportation costs, the effects of conservation, weather, geophysical and technology, refining and processing disruptions, exchange rates, taxes and regulations and other matters affecting the supply and demand dynamics for oil, technological advances, regional market conditions, transportation capacity and costs in producing areas and the effect of changes in these variables on market perceptions.

California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources. There is a closer correlation of prices in California to Brent pricing than to WTI. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.

Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.

Natural gas prices and differentials are strongly affected by local market fundamentals, as well as availability of transportation capacity from producing areas. Due to much lower levels of natural gas production compared to our oil production, the changes in natural gas prices have a smaller impact on our operating results.

Higher natural gas prices have a net negative effect on our operating results. We use a substantial amount of natural gas for our steamfloods and power generation, in addition to selling natural gas. The negative impact of higher prices on our operating costs is, however, partially offset by higher natural gas sales.

Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by three of our cogeneration facilities under long-term contracts. The price we obtain for our excess power impacts our earnings but generally by an insignificant amount.

Seasonality

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities. These seasonal conditions can occasionally pose challenges in our Utah and Colorado operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires.

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Production, Prices and Costs

The following table sets forth information regarding total production, average daily production, average prices and average costs for each of the periods indicated.

	Berry Corp. (Successor)			Berry LLC (Predecessor)
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
										2016			2015
Average daily production:
Oil (MBbls/d)		20.0			19.5			23.9			23.1			30.0
Natural Gas (MMcf/d)		57.2			71.7			78.6			78.1			92.7
NGL (MBbls/d)		2.6			5.2			3.7			3.6			2.9
Total (MBoe/d)		32.2			36.6			40.7			39.7			48.4
Weighted averages realized prices:
Oil (per Bbl)	$	44.86		$	46.94		$	34.00		$	35.83		$	42.27
Natural gas (per Mcf)	$	2.69		$	3.42		$	2.15		$	2.31		$	2.66
NGL (per Bbl)	$	21.67		$	18.20		$	16.08		$	17.67		$	20.27
Average index prices:
Oil (per Bbl)—Brent	$	51.70		$	55.72		$	42.97		$	45.00		$	53.64
Oil (per Bbl)—WTI	$	48.45		$	53.04		$	41.33		$	43.32		$	48.80
Natural gas (per MMBtu)—NYMEX Henry Hub	$	3.03		$	3.66		$	2.29		$	2.46		$	2.66
Costs and other items (per Boe of production):
Lease operating expenses	$	15.81		$	13.06		$	12.42		$	12.73		$	13.88
Electricity generation expenses	$	1.48		$	1.48		$	1.09		$	1.18		$	1.02
Electricity sales	$	(2.26	)	$	(1.69	)	$	(1.57	)	$	(1.60	)	$	(1.39	)
Transportation expenses	$	2.71		$	2.86		$	2.91		$	2.86		$	2.95
Marketing expenses	$	0.24		$	0.30		$	0.19		$	0.21		$	0.22
Marketing revenues	$	(0.28	)	$	(0.29	)	$	(0.25	)	$	(0.25	)	$	(0.32	)
General and administrative expenses	$	5.78		$	3.68		$	5.85		$	5.45		$	4.87
Depreciation, depletion and amortization	$	7.03		$	13.02		$	12.54		$	12.26		$	14.23
Taxes, other than income taxes	$	3.65		$	2.41		$	1.85		$	1.73		$	4.00

The following table sets forth average daily production by operating area:

	Berry Corp. (Successor)		Berry LLC (Predecessor)
	Seven Months Ended September 30, 2017		Two Months Ended February 28, 2017		Nine Months Ended September 30, 2016		Year Ended December 31,
							2016		2015
Average daily production (MBoe/d):
California(1)		17.4		17.0		21.0		20.2		25.8
Hugoton basin(2)		6.5		10.8		9.5		9.5		9.9
Uinta basin		5.4		5.4		5.9		5.8		8.0
Piceance basin		1.9		2.3		3.0		2.9		3.1
East Texas		1.0		1.1		1.3		1.3		1.6
		32.2		36.6		40.7		39.7		48.4

(1) On July 31, 2017, we purchased the remaining approximately 84% working interest of our South Belridge Hill property, located in Kern County, California.

(2) On July 31, 2017, we sold our 78% working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle. Our Hugoton assets represented approximately 24% of our average net daily production for the year ended December 31, 2016.

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Average daily production volumes were 32.2 MBoe/d, 36.6 MBoe/d and 40.7 MBoe/d for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. Our average daily production volumes decreased in the nine months ended September 30, 2017 when compared to the same period in 2016, primarily due to reduced development capital spending in 2016 and early 2017 and the Hugoton Disposition in July 2017, partially offset by the additional oil volumes from the Hill Acquisition in July 2017.

The decreases in average daily production volumes in 2016, compared to 2015, primarily reflected reduced development capital spending throughout our various operating areas, as well as marginal well shut-ins, driven by continued low commodity prices. The decrease in average daily production volumes in California in 2016 also reflected operational challenges in our Diatomite development program. These challenges included a steaming and producing strategy, developed in a higher commodity price environment, that favored oil production over steam oil ratios (efficiency). Application of this strategy, while effective with higher commodity prices, resulted in uneconomic production that was shut in when oil prices declined. The areas with the highest steam oil ratios were generally the deeper, lower oil saturated zones. In 2017, we pursued various alternative strategies to address well performance, including: a refined steaming and producing strategy to optimize the steam oil ratio, re-completing wells in higher oil saturated pay zones, and focusing on the shallow areas. We have reduced historic capital spending in this program until results from the new strategies materialize. The decrease in average daily production volumes in the Uinta Basin operating area in 2016 also reflects lower production volumes as a result of wells that were uneconomic to return to production.

We report electricity and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties.

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Results of Operations

Seven Months Ended September 30, 2017, Two Months Ended February 28, 2017 and Nine Months Ended September 30, 2016

The following table presents our results of operations for each of the periods presented.

	Berry Corp. (Successor)			Berry LLC (Predecessor)
	Seven Months Ended   September 30,   2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016
	(unaudited)			(unaudited)			(unaudited)
	(in thousands)
Revenues and other:
Oil, natural gas and NGL sales	$	237,324		$	74,120		$	285,538
Electricity sales		15,517			3,655			17,573
Gains on oil and natural gas derivatives		5,642			12,886			1,642
Marketing revenues		1,901			633			2,743
Other revenues		3,902			1,424			5,634
	$	264,286		$	92,718		$	313,130
Expenses:
Lease operating expenses		108,751			28,238			138,557
Electricity generation expenses		10,192			3,197			12,118
Transportation expenses		18,645			6,194			32,518
Marketing expenses		1,674			653			2,173
General and administrative expenses		39,791			7,964			65,313
Depreciation, depletion and amortization		48,392			28,149			139,980
Impairment of long-lived assets		—			—			1,030,588
Taxes, other than income taxes		25,113			5,212			20,614
Gains on sale of assets and other, net		(20,687	)		(183	)		(137	)
		231,871			79,424			1,441,724
Other income and (expenses)
Interest expense		(12,482	)		(8,245	)		(48,719	)
Other, net		4,070			(63	)		(79	)
Reorganization items, net		(1,001	)		(507,720	)		(38,829	)
Loss before income taxes		23,002			(502,734	)		(1,216,221	)
Income tax expense		9,190			230			196
Net income (loss)	$	13,812		$	(502,964	)	$	(1,216,417	)

Revenues and Other

Oil, natural gas and NGL sales were approximately $237 million, $74 million and $286 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. Oil, natural gas and NGL sales increased for the nine months ended September 30, 2017 when compared to the same period in 2016 primarily due to an increase in realized prices

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and increased oil production as a result of the Hill Acquisition, partially offset by reduced natural gas production as a result of the Hugoton Disposition and decline in oil and gas production.

Electricity sales were approximately $16 million, $4 million and $18 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. Electricity sales increased for the nine months ended September 30, 2017 when compared to the same period in 2016 primarily due to higher volumes sold externally because of lower internal usage as well as higher prices.

Gains on oil and natural gas derivatives were approximately $6 million, $13 million and $2 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The increase in gains for the nine months ended September 30, 2017 when compared to the same period in 2016 was primarily due to increased hedging activity, a significant portion of which was required by our credit facilities, and improved commodity prices relative to the fixed prices of our derivative contracts.

Expenses

Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses were approximately $109 million, $28 million and $139 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. Lease operating expenses for the nine months ended September 30, 2017 were comparable to the same period in 2016. Lease operating expenses per Boe increased from the nine months ended September 30, 2017 when compared to the same period in 2016 primarily due to the effect of the Hugoton Disposition (natural gas production) and the Hill Acquisition (oil production) and our production decline as a result of decreased activity and a reduction of steamflooding. The conversion of natural gas to barrels of oil equivalent based on energy content (6:1) as opposed to using a price conversion ratio (currently greater than 6:1) results in a comparatively higher production number on a barrels of oil equivalent basis. Thus, replacing natural gas production with oil production in 2017 had a disproportionate impact on our costs per Boe when comparing these respective periods.

Electricity generation expenses were approximately $10 million, $3 million and $12 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The increase for the nine months ended September 30, 2017 when compared to the same period in 2016, was primarily due to the increase in the price of natural gas used in steam generation.

Transportation expenses were approximately $19 million, $6 million and $33 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The decrease for the nine months ended September 30, 2017 when compared to the same period in 2016, was primarily due to the cancellation of uneconomic contracts in the Chapter 11 Proceedings and the Hugoton Disposition, which required significant transportation expenses.

Marketing expenses were approximately $2 million, $0.7 million and $2 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The increase in marketing expenses for the nine months ended September 30, 2017, when compared to the same period in 2016, was primarily due to the increase in the price of natural gas.

General and administrative expenses were approximately $40 million, $8 million and $65 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The decrease for the nine months ended September 30, 2017 when compared to the same period in 2016, was primarily due to the management change in conjunction with our emergence from bankruptcy. The reduction in absolute dollars offset by lower production resulted in lower general and administrative expenses per Boe for the nine months ended September 30, 2017 when compared to the same period in 2016. General and administrative expenses include non-recurring restructuring and other costs of

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approximately $27 million and non-cash stock compensation costs of approximately $1 million for the seven months ended September 30, 2017. General and administrative expenses in 2016 mainly consisted of allocations from our parent company at the time.

Depreciation, depletion and amortization was approximately $48 million, $28 million and $140 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The decrease for the nine months ended September 30, 2017 when compared to the same period in 2016, was primarily due to the fair market revaluation of our assets in fresh-start accounting resulting in a lower depreciable asset base. The reduction in absolute dollars offset by lower production resulted in lower depreciation, depletion and amortization per Boe for the nine months ended September 30, 2017 when compared to the same period in 2016.

Impairment of Long-Lived Assets

We recorded the following noncash impairment charges associated with proved oil and natural gas properties:

	Berry Corp. (Successor)		Berry LLC (Predecessor)
	Seven Months Ended   September 30,   2017		Two Months Ended February 28, 2017		Nine Months Ended September 30, 2016
	(in thousands)
California operating area	$	—	$	—	$	984,288
Uinta basin operating area		—		—		26,677
East Texas operating area		—		—		6,387
Piceance basin operating area		—		—		—
Proved oil and natural gas properties		—		—		1,017,352
California operating area and unproved oil and natural gas properties		—		—		13,236
Impairment of long-lived assets	$	—	$	—	$	1,030,588

The impairment charge of $1.0 billion for the nine months ended September 30, 2016 was primarily due to a decline in commodity prices and changes in expected capital development resulting in a decline of our proved reserves.

Taxes, Other Than Income Taxes

	Berry Corp. (Successor)		Berry LLC (Predecessor)
	Seven Months Ended   September 30,   2017		Two Months Ended February 28, 2017		Nine Months Ended September 30, 2016
	(in thousands)
Severance taxes	$	6,752	$	1,540	$	4,151
Ad valorem taxes		9,401		2,108		7,028
Greenhouse gas allowances		8,960		1,564		9,303
Other		—		—		132
	$	25,113	$	5,212	$	20,614

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Taxes, other than income taxes were approximately $25 million, $5 million and $21 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. Severance taxes, which are a function of revenues generated from production in certain jurisdictions, increased for the nine months ended September 30, 2017 when compared to the same period in 2016, primarily from increased commodity prices partially offset by lower production. Ad valorem taxes, which are based on the value of reserves and production equipment, and vary by location, increased from the nine months ended September 30, 2017 when compared to the same period in 2016, as a result of higher estimated valuations by various tax authorities based on increased commodity prices. Greenhouse gas allowances increased from the nine months ended September 30, 2017 when compared to the same period in 2016, primarily due to higher emissions from increased development activity and an increase in the price of allowances.

Gains on sales of assets and other, net were approximately $21 million, $0.2 million and $0.1 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The increase for the nine months ended September 30, 2017 when compared to the same period in 2016 was primarily due to the Hugoton Disposition.

Other income and (expenses)

	Berry Corp. (Successor)			Berry LLC (Predecessor)
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016
	(in thousands)
Interest expense, net of amounts capitalized	$	(12,482	)	$	(8,245	)	$	(48,719	)
Other, net		4,070			(63	)		(79	)
	$	(8,412	)	$	(8,308	)	$	(48,798	)

Interest expense decreased for the nine months ended September 30, 2017 when compared to the same period in 2016, primarily due to reduced debt resulting from the bankruptcy. Other, net for the nine months ended September 30, 2017, primarily consists of a refund of a federal tax overpayment.

Reorganization items, net were approximately $1 million, $508 million and $39 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. Reorganization items, net increased for the nine months September 30, 2017 when compared to the same period in 2016, primarily due to the impact from the application of fresh-start accounting in conjunction with our emergence from bankruptcy.

Income tax expense was approximately $9 million, $230,000 and $196,000 for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. Income tax expense increased for the nine months ended September 30, 2017 when compared to the same period in 2016, due to the change in our federal and state tax status in connection with our emergence from bankruptcy.

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Years Ended December 31, 2016 and 2015

The following table presents our results of operations for each of the periods presented.

	Berry LLC (Predecessor)
	Year Ended December 31,
	2016			2015
	(in thousands)
Revenues and other:
Oil, natural gas and NGL sales	$	392,345		$	575,031
Electricity sales		23,204			24,544
(Losses) gains on oil and natural gas derivatives		(15,781	)		29,175
Marketing revenues		3,653			5,709
Other revenues		7,570			7,195
		410,991			641,654
Expenses:
Lease operating expenses		185,056			245,155
Electricity generation expenses		17,133			18,057
Transportation expenses		41,619			52,160
Marketing expenses		3,100			3,809
General and administrative expenses		79,236			85,993
Depreciation, depletion and amortization		178,223			251,371
Impairment of long-lived assets		1,030,588			853,810
Taxes, other than income taxes		25,113			70,593
Gains on sale of assets and other, net		(109	)		(1,919	)
		1,559,959			1,579,029
Other income and (expenses)		(61,450	)		(77,870	)
Reorganization items, net		(72,662	)		—
Loss before income taxes		(1,283,080	)		(1,015,245	)
Income tax expense (benefit)		116			(68	)
Net loss	$	(1,283,196	)	$	(1,015,177	)

Revenues and Other

Oil, natural gas and NGL sales decreased by approximately $183 million, or 32%, to approximately $392 million for the year ended December 31, 2016, from approximately $575 million for the year ended December 31, 2015, due to lower oil, natural gas and NGL prices and lower production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $55 million, $10 million and $3 million, respectively.

Electricity sales decreased by approximately $1 million, or 5%, to approximately $23 million for the year ended December 31, 2016, from approximately $25 million for the year ended December 31, 2015, primarily due to decreases in the average sales price of electricity partially offset by an increase in electric power sold during the period.

Losses on oil and natural gas derivatives were approximately $16 million for the year ended December 31, 2016, compared to gains of approximately $29 million for the year ended December 31, 2015, representing a variance of approximately $45 million. Losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts.

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Marketing revenues and other revenues decreased by approximately $2 million, or 13%, to approximately $11 million for the year ended December 31, 2016, from approximately $13 million for the year ended December 31, 2015. The decrease was primarily due to lower marketing revenues principally due to a decrease in natural gas prices partially offset by higher helium sales revenue in the Hugoton basin. In 2015 and 2016, marketing revenues primarily represent third-party activities associated with our long-term firm transportation contracts. These contracts were cancelled in connection with our predecessor company’s bankruptcy. Sales of third-party natural gas are recorded as marketing revenues and other revenues primarily include helium sales revenue.

Expenses

Lease operating expenses decreased by approximately $60 million, or 25%, to approximately $185 million for the year ended December 31, 2016, from approximately $245 million for the year ended December 31, 2015. The decrease was primarily due to cost savings initiatives and lower workover activities, as well as lower prices for natural gas used in steam generation and a decrease in steam injection volumes. Lease operating expenses per Boe also decreased to $12.73 per Boe for the year ended December 31, 2016, from $13.88 per Boe for the year ended December 31, 2015.

Electricity generation expenses decreased by approximately $1 million, or 5%, to approximately $17 million for the year ended December 31, 2016, from approximately $18 million for the year ended December 31, 2015, primarily due to a decrease in natural gas fuel cost partially offset by an increase in natural gas fuel volumes purchased.

Transportation expenses decreased by approximately $11 million, or 20%, to approximately $42 million for the year ended December 31, 2016, from approximately $52 million for the year ended December 31, 2015, primarily due to reduced costs as a result of certain contracts terminated in the Chapter 11 Proceeding and lower production volumes.

Purchases of third-party natural gas are recorded as marketing expenses. Marketing expenses decreased by approximately $1 million, or 19%, to approximately $3 million for the year ended December 31, 2016, from approximately $4 million for the year ended December 31, 2015, primarily due to a decrease in natural gas prices.

General and administrative expenses decreased by approximately $7 million, or 8%, to approximately $79 million for the year ended December 31, 2016, from approximately $86 million for the year ended December 31, 2015. The decrease was primarily due to lower costs allocated to our predecessor company by Linn Operating, Inc. (“Linn Operating”), principally as a result of reduced salaries and benefits related expenses at Linn Operating, partially offset by higher professional services expenses principally related to prepetition strategic alternatives activities Linn Operating pursued on behalf of our predecessor company. General and administrative expenses per Boe increased to $5.45 per Boe for the year ended December 31, 2016, from $4.87 per Boe for the year ended December 31, 2015.

Depreciation, depletion and amortization decreased by approximately $73 million, or 29%, to approximately $178 million for the year ended December 31, 2016, from approximately $251 million for the year ended December 31, 2015. The decrease was primarily due to lower rates as a result of the impairments recorded in the prior year and the first quarter of 2016, as well as lower total production volumes. Depreciation, depletion and amortization per Boe also decreased to $12.26 per Boe for the year ended December 31, 2016, from $14.23 per Boe for the year ended December 31, 2015.

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Impairment of Long-Lived Assets

We recorded the following noncash impairment charges associated with proved oil and natural gas properties:

	Berry LLC
	Year Ended December 31,
	2016		2015
	(in thousands)
California operating area	$	984,288	$	537,511
Uinta basin operating area		26,677		111,339
East Texas operating area		6,387		78,437
Piceance basin operating area		—		55,344
Proved oil and natural gas properties		1,017,352		782,631
California operating area unproved oil and natural gas properties		13,236		71,179
Impairment of long-lived assets	$	1,030,588	$	853,810

The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in our estimates of proved reserves.

Taxes, Other Than Income Taxes

	Berry LLC
	Year Ended December 31,
	2016		2015
	(in thousands)
Severance taxes	$	7,968	$	8,248
Ad valorem taxes		10,951		44,980
Greenhouse gas allowances		6,063		17,363
Other		131		2
	$	25,113	$	70,593

Taxes, other than income taxes decreased by approximately $45 million, or 64%, to approximately $25 million for the year ended December 31, 2016, compared to $71 million for the year ended December 31, 2015. Severance taxes decreased primarily due to lower oil, natural gas and NGL prices and lower production volumes, partially offset by reduced incentives on certain wells in the Uinta basin operating area for 2016 compared to 2015. Ad valorem taxes decreased primarily due to lower estimated valuations on certain of our properties. Greenhouse gas allowances decreased primarily due to lower anticipated emissions compliance obligations as a result of reduced capital spending levels and a decrease in steam injection volumes.

Other Income and (Expenses)

	Berry LLC
	Year Ended December 31,
	2016			2015
	(in thousands)
Interest expense, net of amounts capitalized	$	(61,268	)	$	(85,818	)
Gain on extinguishment of debt		—			11,209
Other, net		(182	)		(3,261	)
	$	(61,450	)	$	(77,870	)

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Other expenses decreased by approximately $16 million to approximately $61 million for the year ended December 31, 2016, compared to the $78 million for the year ended December 31, 2015. Interest expense decreased primarily due to our discontinuation of interest expense recognition on our Unsecured Notes for the period from May 12, 2016 through December 31, 2016, as a result of the Chapter 11 Proceeding, and lower outstanding debt during the period. For the period from May 12, 2016 through December 31, 2016, contractual interest, which was not recorded, on the senior notes was approximately $35 million.

Reorganization Items, Net

We have incurred significant costs associated with our reorganization through bankruptcy. Reorganization items represent costs and income directly associated with the Chapter 11 Proceeding since the May 11, 2016, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.

The following table summarizes the components of reorganization items included on the statement of operations:

	Year ended December 31, 2016
	(in thousands)
Legal and other professional advisory fees	$	(30,130	)
Unamortized premiums		10,923
Terminated contracts(1)		(55,148	)
Other		1,693
	$	(72,662	)

(1) In connection with our emergence from bankruptcy, we terminated or renegotiated more favorable terms for several firm transportation and oil sales contracts.

Income Tax Expense (Benefit) Prior to the consummation of the Plan, Berry LLC was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly pay federal and state income taxes, and did not recognize federal and state income taxes for the operations of Berry LLC. Following emergence from bankruptcy, Berry Corp. is taxed as a corporation. Berry LLC recognized income tax expense of approximately $116 thousand for the year ended December 31, 2016, compared to an income tax benefit of approximately $68 thousand for the year ended December 31, 2015.

Liquidity and Capital Resources

Currently, we expect our primary sources of liquidity and capital resources will be internally generated free cash flow from operations after debt service, or levered free cash flow, and as needed, borrowings under the RBL Facility. Depending upon market conditions and other factors, we could also issue equity and debt securities; however, we expect our operations to continue to generate sufficient levered free cash flow at current commodity prices to fund maintenance operations and organic growth. We believe our liquidity and capital resources will be sufficient to conduct our business and operations for the next twelve months. We completed the 2018 Notes Offering in February of 2018 and used a portion of the proceeds to repay borrowings under our RBL Facility.

The RBL Facility contains certain financial covenants, including the maintenance of (i) a Leverage Ratio (as defined in the RBL Facility) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the RBL Facility) not to be less than 1.00:1.00. As of September 30, 2017 our Leverage Ratio and Current Ratio were 2.50 and 1.46,

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respectively. In addition, the RBL Facility currently provides that to the extent we incur certain unsecured indebtedness, including any amounts raised in this offering, our borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured indebtedness. As of              , 2018 our borrowing base was approximately $             million and we had $             million available for borrowing under the RBL Facility. At September 30, 2017, we were in compliance with the financial covenants under the RBL Facility.

Historically, our predecessor company utilized funds from debt offerings, borrowings under its credit facility and net cash provided by operating activities, as well as funding from our former parent, for capital resources and liquidity, and the primary use of capital was for the development of oil and natural gas properties. For the years ended December 31, 2016 and 2015, our predecessor company’s capital expenditures were approximately $26 million and $152 million, respectively, on an accrual basis including amounts paid by Linn Energy and excluding acquisitions.

We have protected a significant portion of our anticipated cash flows through our commodity hedging program, including through fixed price derivative contracts. As of January 4, 2018, we have hedged approximately 6.4 MMBbls for 2018, 5.0 MMBbls for 2019 and 0.4 MMBbls for 2020 of crude oil production.

Future cash flows are subject to a number of variables discussed in “Risk Factors”. Further, our capital investment budget for the year ended December 31, 2018, does not allocate any amounts for acquisitions of oil and natural gas properties. If we make acquisitions, we would be required to reduce the expected level of capital investments or seek additional capital. If we require additional capital we may seek such capital through borrowings under the RBL Facility, joint venture partnerships, production payment financings, asset sales, additional offerings of debt or equity securities or other means. We cannot be sure that needed capital would be available on acceptable terms or at all. If we are unable to obtain funds on acceptable terms, we may be required to curtail our current development programs, which could result significant declines in our production.

See “—Our Capital Budget” for a description of our 2018 capital expenditure budget.

Statements of Cash Flows

The following is a comparative cash flow summary:

	Berry Corp. (Successor)			Berry LLC (Predecessor)
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
										2016			2015
	(in thousands)
Net cash:
Provided by (used in) operating activities	$	88,364		$	(30,176	)	$	3,269		$	12,345		$	122,518
(Used in) provided by investing activities		(74,563	)		(3,133	)		27,056			18,816			101,368
(Used in) provided by financing activities		(43,049	)		35,000			(1,701	)		(1,701	)		(224,449	)
Net (decrease) increase in cash and cash equivalents	$	(29,248	)	$	1,691		$	28,624		$	29,460		$	(563	)

Operating Activities

Cash provided by operating activities increased for the nine months ended September 30, 2017 when compared to the same period in 2016, primarily due to the increases in the price of oil and natural gas, decreases in costs incurred in conjunction with our emergence from bankruptcy and improvement in working capital items.

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Cash provided by operating activities for the year ended December 31, 2016, was approximately $12 million, compared to approximately $123 million for the year ended December 31, 2015. The decrease was primarily due to lower commodity prices and lower production volumes, as well as lower cash settlements on derivatives and costs related to the bankruptcy.

Investing Activities

The following provides a comparative summary of cash flow from investing activities:

	Berry Corp. (Successor)			Berry Corp. (Successor)
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
										2016			2015
	(in thousands)
Capital expenditures (1)	$	(52,572	)	$	(3,158	)	$	(26,534	)	$	(34,796	)	$	(50,374	)
Settlement of advance to affiliate		—			—			—			—			129,217
(Increase) in restricted cash		—			—			53,418			53,418			—
Purchase of properties and equipment and other		(256,814	)		—			—			—			—
Deposits for acquisitions of oil and gas properties		—			—			—			—			—
Proceeds from sale of properties and equipment and other		234,823			25			172			194			22,525
Cash (used in) provided by investing activities:	$	(74,563	)	$	(3,133	)	$	27,056		$	18,816		$	101,368

(1) Based on actual cash payments rather than accrual.

Cash used in investing activities was approximately $75 million and $3 million for the seven months ended September 30, 2017 and the two months ended February 28, 2017, respectively, and cash provided by investing activities was approximately $27 million during the nine months ended September 30, 2016. The increase in cash used for investing activities from the nine months ended September 30, 2017 when compared to the same period in 2016, was primarily due to the Hill Acquisition, partially offset by the Hugoton Disposition. Capital expenditures were approximately $53 million, $3 million and $27 million for the seven months ended September 30, 2017, the two months ended February 28, 2017 and the nine months ended September 30, 2016, respectively. The increase from the nine months ended September 30, 2017 when compared to the same period in 2016, was primarily due to development of oil and gas properties as a result of increased liquidity. Our liquidity improved significantly in 2017 due to our emergence from bankruptcy and improved commodity prices.

Cash provided by investing activities for the year ended December 31, 2016, was approximately $19 million, compared to approximately $101 million for the year ended December 31, 2015. On September 30, 2015, LINN Energy repaid in full its remaining advance of approximately $129 million. The decrease was primarily due to the settlement of this advance. Capital expenditures were $26 million in 2016 and decreased from 2015 primarily due to lower spending on development activities throughout our various operating areas as a result of continued low commodity prices, partially offset by funding our own development operations, rather than LINN Energy spending on our behalf. For the year ended December 31, 2015, LINN Energy spent approximately $165 million on capital expenditures in respect of our operations. In addition, during the second quarter of 2016, restricted cash decreased by approximately $53 million as a result of an amendment to the Pre-Emergence Credit Facility and restructuring support agreement.

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Financing Activities

Cash used in financing activities was approximately $43 million for the seven months ended September 30, 2017, and was primarily related to repayments on the prior Emergence Credit Facility offset by borrowings on the new RBL Facility. Cash provided by financing activities was approximately $35 million for the two months ended February 28, 2017 and was primarily related to the receipt of proceeds from the issuance of our Series A Preferred Stock offset by repayments on the Pre-Emergence Credit Facility. Cash used in financing activities was approximately $2 million for the nine months ended September 30, 2016, and was primarily related to repayments of the Pre-Emergence Credit Facility.

Cash used in financing activities of approximately $2 million for the year ended December 31, 2016, was related to the repayment of a portion of the borrowings outstanding under the Pre-Emergence Credit Facility. Cash used in financing activities of approximately $224 million for the year ended December 31, 2015, was primarily related to the repayment of a portion of the borrowings outstanding under the Pre-Emergence Credit Facility, cash distributions to LINN Energy and repurchases of senior notes, partially offset by capital contributions made by LINN Energy to our predecessor company. In addition, in May 2015, LINN Energy made a capital contribution of $250 million to our predecessor company, which was deposited on our predecessor company’s behalf and posted as restricted cash with our predecessor company’s lenders in connection with the reduction of its borrowing base.

Debt

2018 Notes Offering

In February 2018, we closed the 2018 Notes Offering of $400 million principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $392 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the 2018 Notes Offering to repay borrowings under the RBL Facility and will use the remainder for general corporate purposes.

We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. We are also entitled to redeem up to 35.0% of the aggregate principal amount of the 2026 Notes before February 15, 2021, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.000% of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any. In addition, prior to February 15, 2021, we may redeem some or all of the 2026 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus any accrued and unpaid interest. If we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 101.0% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.

The 2026 Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The notes are fully and unconditionally guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries (other than Berry LLC). The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the 2026 Notes.

The indenture governing the 2026 Notes contains restrictive covenants that may limit our ability to, among other things:

• incur or guarantee additional indebtedness or issue certain types of preferred stock;

• pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness

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• transfer or sell assets;

• make investments;

• create certain liens securing indebtedness;

• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

• consolidate, merge or transfer all or substantially all of our assets; and

• engage in transactions with affiliates.

The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of our subsidiaries.

RBL Facility

On July 31, 2017, Berry LLC, as borrower, entered the RBL Facility. The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments. The RBL Facility also provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the RBL Facility on a dollar for dollar basis. As of              , 2018, Berry LLC had $             million in borrowings and $             million in letters of credit outstanding under the RBL Facility. As of the date of this prospectus, the borrowing base is set at $            million. Borrowing base redeterminations become effective on or about each May 1 and November 1, although each of the borrower and the administrative agent may make one interim redetermination between scheduled redeterminations. The RBL Facility matures on July 29, 2022, unless earlier terminated in according with the RBL Facility.

The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary London interbank offered rate plus an applicable margin ranging from 2.50% to 3.5% per annum, and (ii) a customary base rate plus an applicable margin ranging from 1.5% to 2.5% per annum, in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average daily unused amount of the borrowing availability under the RBL Facility. We have the right to prepay any borrowings under the RBL Facility with prior notice at any time without a prepayment penalty, other than customary “breakage” costs with respect to eurodollar loans.

Berry Corp. guarantees, and each future subsidiary of Berry Corp. (other than Berry LLC), with certain exceptions, is required to guarantee, our obligations and obligations of the other guarantors under the RBL Facility and under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). In addition, pursuant to a Guaranty Agreement dated as of July 31, 2017 (the “Guaranty Agreement”), Berry LLC guarantees the Guaranteed Obligations. The obligations of Berry LLC and the guarantors are secured by liens on substantially all of our personal property, subject to customary exceptions. Pursuant to the requirements of the RBL Facility, with certain exceptions, any future subsidiaries of Berry LLC will also have to become pledgers and grantors.

The RBL Facility requires us to maintain on a consolidated basis as of September 30, 2017 and each quarter-end thereafter (i) a leverage ratio of no more than 4.00 to 1.00 and (ii) a current ratio of at least 1.00 to 1.00. The RBL Facility also contains customary restrictions that may limit our ability to, among other things:

• incur or guarantee additional indebtedness;

• transfer or sell assets;

• make loans to others;

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• make investments;

• merge with another entity;

• make or declare dividends

• hedge future production or interest rates;

• enter into transactions with affiliates;

• incur liens; and

• engage in certain other transactions without the prior consent of the lenders.

The RBL Facility also contains customary events of default and remedies for credit facilities of a similar nature. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral.

Pre-Emergence Credit Facility and Emergence Credit Facility

As of December 31, 2016, we had approximately $898 million in total borrowings outstanding (including approximately $7 million in outstanding letters of credit) under the Pre-Emergence Credit Facility and no remaining availability. All outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated on the Effective Date. Also on the Effective Date, Berry LLC entered into the Emergence Credit Facility. Borrowings under the RBL Facility were primarily incurred to repay borrowings made under the Emergence Credit Facility. All outstanding obligations under the Emergence Credit Facility were canceled and the agreements governing these obligations were terminated on July 31, 2017.

Unsecured Notes

During the year ended December 31, 2015, we repurchased at a discount, on the open market and through a privately negotiated transaction, approximately $65 million of our Unsecured Notes. In connection with our emergence from the Chapter 11 Proceeding, all outstanding obligations under the Unsecured Notes, were canceled and the indentures and related agreements governing those obligations were terminated.

Lawsuits, Claims, Commitments, Contingencies and Contractual Obligations

In the normal course of business, we, or our subsidiary, are subject to lawsuits, environmental and other claims and other contingencies that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

On May 11, 2016 our predecessor company filed the Chapter 11 Proceeding. Our bankruptcy case was jointly administered with that of LINN Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding. On the Effective Date, the Plan became effective and was implemented. The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims.

In March 2017, Wells Fargo Bank, N.A. (“Wells”), the administrative agent under the Pre-Emergence Credit Facility, filed a motion in the Bankruptcy Court seeking payment of post-petition default interest in the amount of approximately $14 million. We have posted a letter of credit for approximately this amount pending the court’s final order. The court resolved Wells’ motion in our favor on November 13, 2017. Wells filed an appeal on November 27, 2017, and the parties are awaiting the ruling of the appellate court.

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We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at September 30, 2017 and December 31, 2016 were not material to our balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations. For information related to Berry LLC’s emergence from bankruptcy and the terms of the RBL Facility, see “—Chapter 11 Bankruptcy and Our Emergence” and “Liquidity and Capital Resources—Debt—New RBL Facility.”

The following is a summary of our commitments and contractual obligations as of September 30, 2017:

	Payments Due
Contractual Obligations	Total		2017		2018-2019		2020-2021		2022 and Beyond
	(in thousands)
Debt obligations:
RBL Facility	$	379,000	$	—	$	—	$	—	$	379,000
Interest(1)		85,795		4,480		35,545		35,545		10,225
Other:
Commodity derivatives		15,155		1,767		12,296		1,092		—
Firm natural gas transportation contracts(2)		10,018		428		3,465		3,476		2,649
Off-Balance Sheet arrangements:
Operating lease obligations		2,639		313		2,326		—		—
Purchase obligations and other(3)		6,589		589		6,000		—		—
	$	499,196	$	7,577	$	59,632	$	40,113	$	391,874

(1) Represents interest on the RBL Facility computed at 4.5% through contractual maturity in 2022.

(2) We enter into certain firm commitments to transport natural gas production to market and to transport natural gas for use in our cogeneration and conventional steam generation facilities. The remaining terms of these contracts range from approximately five to seven years and require a minimum monthly charge regardless of whether the contracted capacity is used or not.

(3) Included in these obligations is a commitment to (i) invest at least $9 million to extend an existing access road in connection with our Piceance assets or construct a new access road or (ii) pay 50% of the difference between $12 million and the actual amount spent on such access road construction prior to the end of 2018. We have not yet obtained an extension for the road obligation, obtained access to an existing road or started construction of a new access road. We may be unable to extend the deadline and may trigger the payment obligation that, if we were unable to resolve through negotiations, would reduce our capital available for investment.

Berry Corp. and Berry LLC have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of September 30, 2017, we are not aware of material indemnity claims pending or threatened against us.

Counterparty Credit Risk

We account for our commodity derivatives at fair value. We had three commodity derivative counterparties at December 31, 2016 and five at September 30, 2017, and did not receive collateral from any of our counterparties. We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangements that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from

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Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with generally accepted accounting principles requires management to select appropriate accounting policies and to make informed estimates and judgments regarding certain items and transactions. Changes in facts and circumstances or discovery of new information may result in revised estimates and judgments, and actual results may differ from these estimates upon settlement. We consider the following to be our most critical accounting policies and estimates that involve management’s judgment and that could result in a material impact on the financial statements due to the levels of subjectivity and judgment.

Fresh-Start Accounting

Upon our emergence from Chapter 11 bankruptcy, we adopted fresh-start accounting which resulted in our becoming a new entity for financial reporting purposes. We were required to adopt fresh-start accounting upon our emergence from Chapter 11 bankruptcy because (i) the holders of existing voting ownership interests of Berry LLC received less than 50% of the voting shares of Berry Corp. the total of all post-petition liabilities and allowed claims, as shown below:

	(in thousands)
Liabilities subject to compromise	$	1,000,336
Pre-petition debt not classified as subject to compromise		891,259
Post-petition liabilities		245,701
Total post-petition liabilities and allowed claims		2,137,296
Reorganization value of assets immediately prior to implementation of the Plan		(1,706,885	)
Excess post-petition liabilities and allowed claims	$	430,411

Upon adoption of fresh-start accounting, the reorganization value derived from the enterprise value was allocated to our assets and liabilities based on their fair values in accordance with GAAP. The Effective Date fair values of our assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The effects of the Plan and the application of fresh-start accounting were reflected in the financial statements as of February 28, 2017, and the related adjustments thereto were recorded on the statement of operations for the two months ended February 28, 2017.

As a result of the adoption of fresh-start accounting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to February 28, 2017 are not comparable to our consolidated financial statements prior to February 28, 2017.

Our consolidated financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to February 28, 2017. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

Reorganization Value

Under GAAP, Berry Corp. determined a value to be assigned to the equity of the emerging entity as of the date of adoption of fresh-start accounting. The Plan and disclosure statement approved by the Bankruptcy Court did not include an enterprise value or reorganization value, nor did the Bankruptcy Court approve a value as part

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of its confirmation of the Plan. Our reorganization value was derived from an estimate of enterprise value, or the fair value of our long-term debt, stockholders’ equity and working capital. Reorganization value approximates the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. Based on the various estimates and assumptions necessary for fresh-start accounting, we estimated our enterprise value as of the Effective Date to be approximately $1.3 billion. The enterprise value was estimated using a sum of parts approach. The sum of parts approach represents the summation of the indicated fair value of the component assets of the Company. The fair value of our assets was estimated by relying on a combination of the income, market and cost approaches.

The estimated enterprise value, reorganization value and equity value are highly dependent on the achievement of the financial results contemplated in our underlying projections. While we believe the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. Additionally, the assumptions used in estimating these values are inherently uncertain and require judgment. The primary assumptions for which there is a reasonable possibility of the occurrence of a variation that would have significantly affected the reorganization value include those regarding pricing, discount rates and the amount and timing of capital expenditures.

Our principal assets are our oil and natural gas properties. The fair values of oil and natural gas properties were estimated using a valuation technique consistent with the income approach, specifically the discounted cash flows method. We also used the market approach to corroborate the valuation results from the income approach. We used a market-based weighted average cost of capital discount rate of 10% for proved and unproved reserves, with further risk adjustment factors applied to the discounted values. The underlying commodity prices embedded in our estimated cash flows are based on the ICE (Brent) and NYMEX Henry Hub forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that we believe will impact realizable prices. Forward curve pricing was used for years 2017 through 2019 and then was escalated at approximately 2.0%.

The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date:

	(in thousands)
Enterprise value	$	1,262,827
Plus: Fair value of non-debt liabilities		298,211
Reorganization value of the Successor’s assets	$	1,561,038

The fair value of non-debt liabilities consists of liabilities assumed by Berry Corp. on the Effective Date and excludes the fair value of long-term debt.

Condensed Consolidated Balance Sheet

The adjustments included in the fresh-start consolidated balance sheet in the accompanying financial statements reflect the effects of the transactions contemplated by the Plan and executed on the Effective Date as well as fair value and other required accounting adjustments resulting from the adoption of fresh-start accounting. The explanatory notes provide additional information with regard to the adjustments recorded, methods used to determine the fair values and significant assumptions.

Oil and Natural Gas Properties

Proved Properties

We account for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all acquisition and development costs of proved properties are capitalized and

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amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. We capitalize interest on borrowed funds related to our share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use.

Additionally, we perform impairment tests with respect to our proved properties when commodity prices are subject to prolonged declines, reserves estimates change significantly, other significant events occur or management’s plans change with respect to these properties in a manner that may impact our ability to realize recorded volumes. Impairment tests incorporate a number of assumptions involving expectations of undiscounted future cash flows, which can change significantly over time. These assumptions include estimates of future commodity prices, which we base on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future operating and development costs. Apart from the effects of commodity prices, we believe our approach to interpreting technical data regarding proved oil and gas reserves makes it more likely that future proved reserves revisions will be positive rather than negative.

Based on the analysis described above, for the years ended December 31, 2016 and December 31, 2015, we recorded noncash impairment charges of approximately $1.0 billion and $783 million, respectively, associated with proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on our statements of operations.

Unproved Properties

A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At September 30, 2017, the net capitalized costs attributable to unproved properties were approximately $517 million. The unproved amounts are not subject to depreciation, depletion and amortization until they are classified as proved properties. However, if the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. We believe our current plans and exploration and development efforts will allow us to realize the carrying value of our unproved property balance at September 30, 2017. Based on the analysis described above, for the years ended December 31, 2016 and December 31, 2015, we recorded noncash impairment charges of approximately $13 million and $71 million, respectively, associated with unproved oil and natural gas properties. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on our statements of operations.

Asset Retirement Obligation

We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is made that a legal obligation exists to dismantle an asset and remediate the property at the end of the useful life and the cost of the obligation can be reasonably estimated.

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The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalize the cost by increasing the related property, plant and equipment (“PP&E”) balances. If the future cost of the AROs changes, we record an adjustment to both the ARO and PP&E. Over time, the liability is increased and expense is recognized through accretion, and the capitalized cost is depreciated over the useful life of the asset.

At certain of our facilities, we have identified AROs that are related mainly to plant and field decommissioning, including plugging and abandonment of wells. In certain cases, we do not know or cannot estimate when we may settle these obligations and therefore we cannot reasonably estimate the fair value of the liabilities. We will recognize these AROs in the periods in which sufficient information becomes available to reasonably estimate their fair values.

Revenue Recognition

We recognize revenue from oil, natural gas and NGL production when title has passed from us to the purchaser, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. We recognize our share of revenues net of any royalties and other third-party share. In addition, we engage in the purchase, gathering and transportation of third-party natural gas and subsequently market such natural gas to independent purchasers under separate arrangements. As a result, we separately report third-party marketing revenues and marketing expenses.

Fair Value Measurements

We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level 3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period. We primarily apply the market approach for recurring fair value measurement, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management’s judgments regarding expectations of projected cash flows and discounts those cash flows using a risk-adjusted discount rate.

The most significant items on our balance sheet that would be affected by recurring fair value measurements are derivatives. Commodity derivatives are carried at fair value. In addition to using market data in determining these fair values, we make assumptions about the risks inherent in the inputs to the valuation technique. Our commodity derivatives comprise Over-the-Counter (“OTC”) bilateral financial commodity contracts, which are generally valued using industry-standard models that consider various inputs, including publicly available prices and forward curves generated from a compilation of data gathered from third parties. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Substantially all of these inputs are observable data or are supported by observable prices at which transactions are executed in the marketplace. We classify these measurements as Level 2.

Our PP&E is written down to fair value if we determine that there has been an impairment in its value. The fair value is determined as of the date of the assessment using discounted cash flow models based on management’s expectations for the future. Inputs include estimates of future production, prices based on commodity forward price curves as of the date of the estimate, estimated future operating and development costs and a risk-adjusted discount rate.

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Other Loss Contingencies

In the normal course of business, we are involved in lawsuits, claims and other environmental and legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis.

Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors.

Recently Issued Accounting Standards

In May 2017, the Financial Accounting Standards Board (“FASB”) issued rules to simplify the guidance on the modification of share-based payment awards. The amendments provide clarity on which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting prospectively. The rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

In January 2017, the FASB issued rules that changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

In November 2016, the FASB issued rules intended to address the diversity in practice in classification and presentation of changes in restricted cash on the statement of cash flows. These rules will be applied retrospectively as of the date of adoption and are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (with early adoption permitted). We are currently evaluating the impact of the adoption of these rules on our financial statements and related disclosures. This is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and require additional disclosures.

In August 2016, the FASB issued rules that modify how certain cash receipts and cash payments are presented and classified in the statement of cash flows. These rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with earlier adoption permitted. We are currently evaluating the impact of these rules on our financial statements.

In June 2016, the FASB issued rules that change how entities will measure credit losses for certain financial assets and other instruments that are not measured at fair value. These rules are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of these rules on our financial statements.

In February 2016, the FASB issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. These rules will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with earlier application permitted. We are currently evaluating the impact of these rules on our financial statements.

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In January 2016, the FASB issued rules that modify how entities measure equity investments and present changes in the fair value of financial liabilities. Unless the investments qualify for a practicality exception, the new rules require all equity investments to be measured at fair value with changes in the fair value recognized through net income (other than those accounted for under the equity method of accounting or those that result in consolidation of the investee). Entities will have to record changes in instrument-specific credit risk for financial liabilities measured under the fair value option in other comprehensive income. These new rules become effective for fiscal years beginning after December 15, 2017 with no early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

During 2016, the FASB issued rules clarifying the new revenue recognition standard issued in 2014. The new rules are intended to improve and converge the financial reporting requirements for revenue from contracts with customers. For non-public companies, these rules are effective for fiscal years beginning after December 15, 2018, including interim periods within those years. We are currently evaluating the impact of the adoption of these rules on our financial statements and related disclosures.

Quantitative and Qualitative Disclosures About Market Risk

Our primary market risks are attributable to fluctuations in commodity prices and interest rates, which can affect our business, financial condition, operating results and cash flows. The following should be read in conjunction with the financial statements and related notes included elsewhere in this prospectus.

Commodity Price Risk

Our most significant market risk relates, to prices of oil, natural gas and NGLs. We expect commodity prices to remain volatile and unpredictable. As commodity prices decline or rise significantly, revenues and cash flows are likewise affected to the extent unhedged or, in the case of falling prices, if hedged counterparties default. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond our control. Future declines in commodity prices may result in noncash write-downs of the carrying amounts of our assets.

We have hedged a large portion of our expected crude oil production and our natural gas requirements to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls and puts to hedge. Our derivatives are primarily in the form of swap contracts, collars and three-way collars. We have not entered into derivative contracts for speculative trading purposes. We continuously consider the level of our production that it is appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity prices, our overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of hedging contained in any credit facility or other debt instrument applicable at the time. Currently, our hedging program mainly consists of swaps. We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our RBL Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standards & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives which mitigates the counterparty nonperformance risk somewhat.

In May 2016 and July 2016, as a result of the Chapter 11 Proceeding, Berry LLC’s counterparties canceled (prior to the contract settlement dates) all of Berry LLC’s then-outstanding derivative contracts, and Berry LLC received net cash proceeds of approximately $2 million. The net cash proceeds received were used to make permanent repayments of a portion of the borrowings outstanding under the Pre-Emergence Credit Facility.

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At December 31, 2016, the fair value of fixed price swaps was a net liability of approximately $17 million. A 10% increase in the index oil and natural gas prices above the December 31, 2016, prices would result in a net liability of approximately $66 million, which represents a decrease in the fair value of approximately $49 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2016, prices would result in a net asset of approximately $31 million, which represents an increase in the fair value of approximately $48 million.

As of September 30, 2017, we had a net derivative liability of $9.6 million carried at fair value, as determined from prices provided by external sources that are not actively quoted. We determine the fair value of our oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.

Actual gains or losses recognized related to our derivative contracts depend exclusively on the price of the underlying commodities on the specified settlement dates provided by the derivative contracts. Additionally, we cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our cash flows could be negatively impacted.

Interest Rate Risk

As of September 30, 2017, we had debt outstanding under the RBL Facility of approximately $379 million, which incurred interest at floating rates. A 1% increase in the respective market rate would result in an estimated $4 million increase in annual interest expense. We used a portion of the proceeds from the 2018 Notes Offering to repay borrowings under our RBL Facility. As of              , we had $            million outstanding under our RBL Facility.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the periods discussed. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we may experience inflationary pressure on the cost of oilfield services and equipment as increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations. An increase in oil, natural gas and NGL prices may cause the costs of materials and services to rise.

Off-Balance Sheet Arrangements

See “—Liquidity and Capital Resources—Lawsuits, Claims, Commitments, Contingencies and Contractual Obligations” for information regarding our off-balance sheet arrangements.

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BUSINESS

Our Company

We are a value-driven, independent oil and natural gas company engaged primarily in the development and production of conventional reserves located in the western United States, including California, Utah, Colorado and Texas. We target onshore, low-cost, low-risk, oil-rich basins, such as the San Joaquin basin of California and the Uinta basin of Utah. The Company’s assets are characterized by:

• high oil content with production consisting of approximately 82% oil;

• long-lived reserves with low and predictable production decline rates;

• an extensive inventory of low-risk development drilling opportunities with attractive full-cycle economics;

• a stable and predictable development and production cost structure; and

• favorable Brent-influenced crude oil pricing dynamics.

Our asset base is concentrated in the San Joaquin basin in California, which has over 100 years of production history and substantial remaining original oil in place. We focus on conventional, shallow reservoirs, the drilling and completion of which are low-cost in contrast to modern unconventional resource plays. Our decades-old proven completion techniques include steamflood and low-volume fracture stimulation.

We focus on enhancing our production, improving drilling and completion techniques, controlling costs and maximizing the ultimate recovery of hydrocarbons from our assets, with the goal of generating top-tier returns. We seek to fund repeatable organic production and reserves growth through the use of internally generated free cash flow from operations after debt service, or levered free cash flow, while also maintaining ample liquidity and a conservative financial leverage profile.

As of November 30, 2017, we had estimated proved reserves of 141,838 MBoe, of which approximately 57% were proved developed producing reserves and approximately 66% of total proved reserves were located in California. For the three months ended September 30, 2017, pro forma for the Hugoton Disposition and the Hill Acquisition, we had average production of approximately 27.0 MBoe/d, of which approximately 82% was oil.

The New Berry

Berry was founded by the entrepreneur and our namesake C. J. Berry in the late 1800s. After making his fortune working a solo-mining operation during the Alaskan gold rush, Mr. Berry returned to California and continued his success with oil exploration and production. Our predecessor company was formed in 1985 after merging several related entities and ultimately became publicly traded beginning in 1987.

In 2013, the Linn Entities acquired our predecessor company for LinnCo, LLC shares and assumed debt with an aggregate value of $4.6 billion. A severe industry downturn, coupled with high leverage and significant fixed charges, led the Linn Entities and, consequently, our predecessor company to initiate the Chapter 11 Proceeding on May 11, 2016.

On February 28, 2017, Berry LLC emerged from bankruptcy as a stand-alone company and wholly-owned subsidiary of Berry Corp. with new management, a new board of directors and new ownership. Through the Chapter 11 Proceeding, the Company significantly improved its financial position from that of Berry LLC while it was owned by the Linn Entities. These improvements included:

• the elimination of approximately $1.3 billion of debt and more than $76 million of annualized interest expense;

• the termination of, or renegotiation of more favorable terms for, several firm transportation and oil sales contracts; and

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• the anticipated reduction in recurring general and administrative costs as a stand-alone company by following a lean operating model.

Today, we foster Mr. Berry’s entrepreneurial spirit and leadership skills. We encourage our teams to apply his business ethos at every level to move us forward. We strive to have a positive presence in the communities surrounding our operations. Our employees belong to the communities where they work, which we believe aligns our interests with those of the people who live near our operations.

Our Reserves and Assets

The majority of our reserves are composed of heavy crude oil in shallow, long-lived reservoirs. Approximately two-thirds of our proved reserves and approximately 90% of the PV-10 value of our proved reserves are derived from our assets in California. We also operate in the Uinta basin in Utah, a stacked, multi-bench, light-oil-prone play with significant undeveloped resources, in the Piceance basin in Colorado, a low geologic risk, prolific natural gas play, and in part of an extensive over-pressured natural gas cell on the western flank of the East Texas basin.

The charts below summarize certain characteristics of our proved reserves and PV-10 of proved reserves as of November 30, 2017 (as described in the table below and in “Prospectus Summary—Summary Reserves and Operating Data”):

1P Reserves by Category (142 MMBoe)	1P Reserves By Commodity (142 MMBoe)
1P Reserves By Area (142 MMBoe)	1P PV-10 by Area ($1.1 billion)

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The tables below summarize our proved reserves and PV-10 by category as of November 30, 2017:

	Proved Reserves and PV-10 as of November 30, 2017 (1)
	Oil (MMBbl)		Natural Gas (Bcf)		NGLs (MMBbl)		Total (MMBoe)		% of Proved		% Proved Developed		Capex(2) ($MM)		PV-10(3) ($MM)
PDP		63		101		1		81		57		93	$	51	$	741
PDNP		6		—		—		6		4		7		10		85
PUDs		32		137		—		55		39		—		489		243
Total		101		238		1		142		100		100	$	550	$	1,069

(1) Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $53.40 per Bbl ICE (Brent) for oil and NGLs and $3.01 per MMBtu NYMEX Henry Hub for natural gas at November 30, 2017. Prices were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules, including adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Please see “Prospectus Summary—Summary Reserves and Operating Data.”

(2) Represents undiscounted future capital expenditures as of November 30, 2017.

(3) PV-10 is a non-GAAP financial measure. For a definition of PV-10, please read “Prospectus Summary—Summary Reserves and Operating Data—PV-10.” PV-10 does not give effect to derivatives transactions. With respect to PV-10 calculated as of November 30, 2017, it is not practical to calculate the taxes for such period because GAAP does not provide for disclosure of standardized measure on an interim basis.

The table below summarizes our average net daily production by basin for the three months ended September 30, 2017, pro forma for the Hugoton Disposition and the Hill Acquisition:

	Pro Forma Average Net Daily Production for the Three Months Ended September 30, 2017
	(MBoe/d)		Oil (%)
California		19.8		100	%
Uinta basin		5.0		48	%
Piceance basin		1.1		2	%
East Texas basin		1.1		—
Total		27.0		82	%

Our Stable Production Base with Low Decline Rates

Our reserves are long-lived and characterized by relatively low production decline rates, which affords capital flexibility through commodity price cycles and allows for efficient hedging of significant quantities of future expected production. The chart below shows our average daily production for the three months ended September 30, 2017, pro forma for the Hill Acquisition and Hugoton Disposition and the estimated production profile of our PDP reserves, derived from our November 30, 2017 reserve report, based on the assumptions and calculations therein.

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PDP Production by Year (MBoe/d) and PDP Decline Rates

Our Development Opportunities

We have an extensive inventory of low-risk, high-return development opportunities. Our inventory currently consists of 790 gross (786 net) identified drilling locations associated with proved undeveloped reserves as of November 30, 2017 with average EURs of approximately 46 MBoe in California and 360 MBoe in Colorado and average estimated drilling and completion costs of approximately $450,000 and $1,800,000, respectively. We also have approximately 1,305 gross (1,300 net) additional identified drilling locations with economics that management believes are similar to those of our proved undeveloped locations. We also have identified more than 3,800 gross (3,500 net) additional drilling locations, the economics of which are currently under review. Our identified drilling locations include 161 gross (161 net) steamflood and waterflood injection wells that we expect to add incremental production. For a discussion of how we identify drilling locations, please see “—Our Reserves and Production Information—Determination of Identified Drilling Locations.”

We operate over 95% of our productive wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, approximately 76% of our acreage is held by production, including 99% of our acreage in California. Our high degree of operational control, together with the large portion of our acreage that is held by production, gives us flexibility over the execution of our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production.

The following table summarizes certain information concerning our acreage, identified drilling locations and producing wells as of November 30, 2017:

	Acreage				Net Acreage Held By Production(%)			Producing Wells, Gross(1)(2)		Average Working Interest (%)(2)(4)			Net Revenue Interest (%)(2)(5)			Identified Drilling Locations(3)
	Gross		Net													Gross		Net
California		10,880		7,945		99	%		2,522		99	%		95	%		3,742		3,731
Uinta basin		143,120		98,804		72	%		912		95	%		79	%		1,246		1,084
Piceance basin		10,553		8,008		85	%		170		72	%		57	%		869		663
East Texas basin		5,853		4,533		100	%		117		99	%		79	%		123		122
Total		170,406		119,290		76	%		3,721		97	%		86	%		5,980		5,600

(1) Includes 469 steamflood and waterflood injection wells in California.

(2) Excludes 91 wells in the Piceance basin each with a 5% working interest and eleven wells in the Permian basin all with less than 0.1% working interest.

(3) Our total identified drilling locations include 790 gross (786 net) locations associated with PUDs as of November 30, 2017, including 161 gross (161 net) steamflood and waterflood injection wells. Please see “—Our Reserves and Production Information—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations.

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(4) Represents our weighted average working interest in our active wells.

(5) Represents our weighted average net revenue interest for the month of September 2017.

Favorable Cost Structure

Our PDP assets are primarily mature, long-lived, oil-weighted, low-decline producing properties. The nature of our reserves requires relatively less development capital to maintain our base production, offsetting moderately higher per barrel operating expenses inherent in mature oil wells. Operating expenses includes lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses net of electricity sales and marketing revenues. In addition, our operating cost structure benefits from relatively stable service costs. As a result, our cost structure is stable and, given the nature of our production base, provides us with significant capital flexibility, and a low break-even operating price. Further, lack of need for advanced equipment in our key operations and the stable cost of the service environment drive substantially lower service costs and provide relative insulation from the cost inflation pressures experienced by our peers who operate primarily in unconventional plays.

Our PUD reserves are expected to have lower operating expenses per Boe compared to our PDP reserves due to the higher rates of production associated with new wells as compared to our older producing wells, which have been producing for an average of 11 years. Our lower expected operating expenses on our PUD reserves supports high full-commodity-cycle margins (including cost of development). The result of our PDP and PUD operating expenses mix is a stable total company cost structure over time, which provides significant through-cycle capital flexibility.

The following chart represents our expected operating expenses per Boe for the next five years as provided to our reserve engineers in connection with the preparation of our November 30, 2017 reserve report:

PUD / PDP Operating Expenses ($/Boe)

Our operating expense estimates are based on, among other things, our current cost structure. Investors should also recognize that the reliability of any guidance diminishes the farther in the future that data are forecast so that it is increasingly likely that our actual results will differ materially from our guidance. See “Risk Factors—Risks Related to Our Business and Industry.”

Other Assets

We produce oil from heavy crude reservoirs using steam to heat the oil so it will flow. Because of our dependence on steam, we own and operate five natural gas cogeneration plants. These plants supply approximately 24% of our steam needs and 43% of our field electricity needs in California at a discount to electricity market prices. To further offset our costs, we also sell surplus power produced by three of our cogeneration facilities under long-term contracts with California utility companies.

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In addition, we own gathering, treatment and storage facilities in California that currently have excess capacity, reducing our need to spend capital to develop nearby assets and generally allowing us to control certain operating costs. We also own a network of oil and gas gathering lines across our assets outside of California, and our oil and natural gas is transported through such lines and third-party gathering systems and pipelines.

We own a natural gas processing plant with capacity of approximately 30 MMcf/d in the Brundage Canyon area, located in Duchesne County, Utah. This facility takes delivery from gathering and compressions facilities we operate. Approximately 95% of the gas gathered at these facilities is produced from wells that we operate. Current throughput at the processing plant is 18 to 20 MMcf/d and sufficient capacity remains for additional large scale development drilling.

Our California Advantage

California is one of the most productive oil and natural gas regions in the world and was the third largest oil producing state in the United States in 2016 according to the EIA, with significant remaining opportunities for production growth with attractive full-cycle returns. The San Joaquin basin in California has produced for over a century. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present low-risk development opportunities. The majority of these reserves are composed of heavy crude oil in shallow, long-lived reservoirs with lower drilling risks and costs compared to deeper reservoirs or shale resource plays.

California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources, and there is a closer correlation of price in California to Brent pricing than to WTI. This dynamic has led to periods where the price for the primary benchmark, Midway-Sunset, a 13° API heavy crude, has been equal to or exceeded the price for WTI, a light 40° API crude.

Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low transportation costs, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.

Our Capital Budget

Following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities, we increased our pace of development and expect to continue to do so in 2018. Our 2018 anticipated capital expenditure budget of approximately $135 to $145 million represents an increase of approximately 84% over our expected 2017 capital expenditures of approximately $74 to $78 million. Based on current commodity prices and a drilling success rate comparable to our historical performance, we believe we will be able to fund our 2018 capital program with our levered free cash flow. We expect to:

• employ:

• two drilling rigs in California continuously through 2018; and

• one additional drilling rig assigned to certain projects in the second half of 2018;

• drill approximately 180 to 190 gross development wells, of which we expect at least 175 will be in California; and

• maintain a fairly constant pace of drilling throughout the year.

The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition

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costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial condition and results of operations.

Our Commodity Hedging Program

We expect our operations to generate substantial cash flows at current commodity prices. We have protected a portion of our anticipated cash flows through 2020 as part of our crude oil hedging program. Our low-decline production base, coupled with our stable operating cost environment, affords us the ability to hedge a material amount of our future expected production. The chart below summarizes our derivative contracts in place as of January 4, 2018.

Hedge Volumes in MMBbls (MBbl/d)

Our Areas of Operation

We have three operating areas in the western United States, including California, the Rockies and East Texas.

California

According to the U.S. Geological Survey as of 2012, the San Joaquin basin in California contained three of the 10 largest oil fields in the United States based on cumulative production and proved reserves. We have operations in two of the largest fields in California—Midway-Sunset and South Belridge. California is one of the most productive oil and natural gas regions in the world and was the third largest oil producing state in the United States in 2016 according to the EIA.

Our California operating area consists of properties located in the Midway-Sunset, South Belridge, McKittrick and Poso Creek fields in the San Joaquin basin in Kern County as well as the Placerita Field in the Ventura basin in Los Angeles County. The producing areas in our Southeast San Joaquin operations include: (i) our Midway-Sunset, Homebase, Formax and Ethel D leases, which are long-life, low-decline, strong-margin oil properties with additional development opportunities; (ii) our Poso Creek property, which is an active mature steamflood asset that we continue to develop across the property; and (iii) our Placerita property, which is a

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mature steamflood asset with additional recompletion opportunities. The producing areas in our Northwest San Joaquin operations include: (i) our McKittrick Field 21Z property, which is a new steamflood development with potential for infill and extension drilling; (ii) our South Belridge Field Hill property, which is characterized by two known reservoirs with low geological risk containing a significant number of drilling prospects, including downspacing opportunities, as well as additional steamflood opportunities; and of which we purchased the remaining approximately 84% working interest in the third quarter of 2017, as described in more detail below; (iii) our thermal Diatomite Midway-Sunset properties, where we utilize innovative EOR techniques to unlock significant value and maximize recoveries; and (iv) our sandstone Midway-Sunset properties, where we use cyclic and continuous steam injection to develop these know reservoirs. Our California proved reserves represented approximately 66% of our total proved reserves at November 30, 2017 and accounted for 18.8 MBoe/d, or 64%, of our actual average daily production for the three months ended September 30, 2017.

According to the EIA, approximately 75% of California’s daily oil production for 2015 was produced in the San Joaquin basin. Commercial petroleum development began in the San Joaquin basin in the late 1860s when asphalt deposits were mined and shallow wells were hand dug and drilled. Rapid discovery of many of the largest oil accumulations followed during the next several decades. We began operations in California in 1909. In the 1960s, introduction of thermal techniques resulted in substantial new additions to reserves in heavy oil fields. The San Joaquin basin contains multiple stacked benches that have allowed continuing discoveries of stratigraphic, structural and non-structural traps. Most oil accumulations discovered in the San Joaquin basin occur in the Eocene age through Pleistocene age sedimentary sections. Organic rich shales from the Monterey, Kreyenhagen and Tumey formations form the source rocks for these accumulations. We believe there are extensive existing field redevelopment opportunities in our areas of operation within the San Joaquin basin. We believe that our California focus and strong balance sheet will allow us to take advantage of these opportunities.

We actively operate and develop 4 fields in the San Joaquin basin consisting of improved oil recovery (“IOR”) and EOR project types. We currently hold approximately 7,093 net acres in the San Joaquin basin with a 99.65% average working interest. We have extensive infrastructure and excess available takeaway capacity in place to support additional development in California. This infrastructure includes five cogeneration facilities, 79 conventional steam generators, gathering lines and processing facilities inclusive of oil and gas processing, water recycling and softening facilities among other standard industry equipment. The majority of our oil production is sold through pipeline connections, and we have contracts in place with third-party purchasers of our crude.

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Stratigraphic Chart of San Joaquin and Ventura basins

California is home to several basins characterized by extensive production history, long reserve life and multiple producing horizons. As shown in the table below, the basins where we operate contain multiple stacked formations throughout their depths that include both conventional and unconventional opportunities. We currently operate in the formations highlighted below; however, we believe the stacked reservoirs within our asset base provide exposure to additional upside potential in several emerging resource plays.

Rockies

Uinta basin

Formed during the late Cretaceous to Eocene periods, the Uinta basin is a mature multi-bench, oil-prone play located primarily in Duchesne and Uintah Counties of Utah and covers more than 15,621 square miles. Exploration efforts immediately after the Second World War led to the first commercial oil discoveries in the Uinta basin. Oil was discovered in, and produced from fluvial to lacustrine sandstones of the Green River formation in these early discoveries. The application of improved hydraulic fracturing techniques in the mid 2000s greatly increased production from the Uinta basin. As reported by the Utah Department of Natural Resources, total Utah production doubled from 36 MBbl/d in 2003 to 84 MBbl/d in 2016. Approximately 80% of Utah’s production in 2016 came from the Uinta basin in Duchesne and Uintah counties.

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Surface indications of petroleum in Utah were noted by explorers as early as 1850, but drilling efforts in the late nineteenth and early twentieth centuries failed to find commercial quantities of oil. The first commercial discoveries were made in the late 1940s in the northern Uinta basin. The Uinta productive area expanded significantly over the last few decades, and the introduction of improved hydraulic fracturing methodologies improved per well recoveries since the mid 2000s. We entered the Uinta basin in 2003 with the acquisition of assets in Brundage Canyon and continued to grow our assets to today. We believe continued exploration and development drilling in the Uinta basin, especially in proximity to our assets, coupled with improvements in drilling and completion techniques will continue to provide us with development and growth opportunities going forward.

Our Uinta basin operations in the Brundage Canyon, Ashley Forest and Lake Canyon areas target the Green River and Wasatch formations that produce oil and natural gas at depths ranging from 5,000 feet to 8,000 feet. We have high operational control of approximately 1,200 identified gross vertical drilling locations and additional behind pipe potential, with significant upside for additional vertical and horizontal development and recompletions on existing acreage. We also have extensive infrastructure and available takeaway capacity in place to support additional development along with existing gas transportation contracts. Rejection of an oil sales contract and various transportation contracts in connection with our predecessor company’s bankruptcy restructuring resulted in significantly improved sales net of royalties, production and transportation expenses. We have a natural gas gathering systems comprised of approximately 500 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. We also own a natural gas processing plant in the Brundage Canyon area with capacity of approximately 30 MMcf/d. Our Uinta basin proved reserves represented approximately 11% of our total proved reserves at November 30, 2017 and accounted for 5.0 MBoe/d, or 17%, of our average daily production for the three months ended September 30, 2017.

Piceance basin

The Piceance basin is located in northwestern Colorado and is a low geologic risk gas play with trillions of cubic feet of natural gas in place. Natural gas generated from coals and carbonaceous shales in the Upper Cretaceous Mesaverde Group migrated into low permeability Mesaverde Group fluvial sandstones resulting in a basin-centered gas accumulation, or what the U.S. Geological Survey terms a “continuous petroleum accumulation.” Operators recognized for years that the Mesaverde Group, and the Williams Fork formation in particular, contained significant quantities of gas over a large area, but the low permeability of the reservoir sandstones made it difficult to complete economic wells. Improvements in hydraulic fracture design and completion fluids in the 1990s and 2000s, coupled with an increase in commodity prices, led to the economic development of the gas resources in the Piceance basin.

Our primary operating areas in the Piceance basin are Garden Gulch and North Parachute where we target the Williams Fork formation of the Mesaverde Group and produce at depths ranging from 7,500 feet to 12,500 feet. In addition to more than 800 identified gross drilling locations and a proven slickwater completion method that has resulted in lower costs and increased recoveries, we have infrastructure and available takeaway capacity in place to support additional development along with existing gas transportation contracts. We have plans to begin development drilling at North Parachute in 2018 using our proven slickwater completion method to move reserves from undeveloped to producing. Our Piceance basin proved reserves represented approximately 21% of our total proved reserves at November 30, 2017 and accounted for 1.1 MBoe/d, or 4%, of our average daily production for the three months ended September 30, 2017.

In addition to the 800 identified gross drilling locations in the Williams Fork formation, we believe significant potential exists in the Late Cretaceous Mancos shale that underlies the Mesaverde group. The Mancos shale is over 4,000 feet thick in the Piceance basin and was deposited in the Cretaceous interior seaway. The unit consists of marine shale along with interbedded sandstone, carbonates and organic units. Operators have successfully drilled and completed commercial wells in the Mancos Shale, and in 2016 the U.S. Geological Survey assessed technically recoverable mean resources of 66 trillion cubic feet of natural gas and 45 MMBbls of NGLs from this continuous petroleum accumulation.

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Stratigraphic Chart of Uinta and Piceance basins

Because of the stratigraphic similarities and shared geologic history between the Uinta and Piceance basins, the U.S. Geological Survey describes the basins as the Uinta-Piceance Petroleum Province. Five total petroleum systems have been identified spanning in age from the Pennsylvanian to the Eocene periods, including both conventional and unconventional opportunities. We produce from the formations highlighted in the following stratigraphic chart, predominantly oil in the Uinta basin and gas in the Piceance basin. The oil produced from the Green River and Wasatch formation reservoirs in the Uinta basin are derived from lacustrine oil-prone source rocks that were deposited in Lake Uinta during the Eocene period. The extent and richness of these petroleum systems across the Uinta-Piceance Petroleum Province provide us development upside in both stacked pays and potential deeper reservoirs.

East Texas

The East Texas basin is part of the larger Jurassic to Cretaceous age East Texas—North Louisiana Salt basin that extends across north eastern Texas into northwestern Louisiana. The basin marks the northern limit of Jurassic salt deposition in the larger Gulf of Mexico province. Drilling began in the East Texas basin in the 1860s in Nacogdoches county at Oil Springs. Many discoveries followed, and in 1930, the large East Texas oil field was discovered with estimated ultimate recoverable reserves of 6 billion Bbls. Continued expansion of production into the Bossier, Cotton Valley and Haynesville formation attests to the richness of the East Texas petroleum province.

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Our East Texas properties, in Harrison and Limestone Counties, are primarily in the Cotton Valley Lime and Bossier Sand which are tight sands characterized by low porosity and permeability and are part of an extensive over-pressured gas cell on the western flank of the East Texas basin. The Cotton Valley formation, extending across East Texas, North Louisiana and Southern Arkansas, has been under development since the early-to-mid 1900s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. Our properties primarily produce natural gas at depths ranging from 7,000 feet to 11,500 feet. Our proved reserves for these mature, low-decline producing properties represented approximately 2% of our total proved reserves at November 30, 2017 and accounted for 1.1 MBoe/d, or 4%, of our average daily production for the three months ended September 30, 2017.

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Stratigraphic Chart of East Texas basin

The stratigraphy of the East Texas basin is complex and consists of a broad spectrum of stacked clastic and carbonate reservoir intervals. Horizons from which we produce extend from the Haynesville shale up through the Cotton Valley, Bossier, Travis Peak to the Pettet sandstones. We believe the stacked nature of the reservoir intervals in the East Texas basin coupled with improved drilling and completion techniques will provide us with new drilling opportunities and the ability to continue expanding our production.

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Our Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategy.

• Stable, low-decline, predictable and oil-weighted conventional asset base. We expect our operations to continue to generate sufficient levered free cash flow at current commodity prices to fund maintenance operations and growth. The majority of our interests are in properties that have produced for decades. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present lower risk than unconventional resource plays. The properties are characterized by long-lived reserves with low production decline rates, stable cost structures and low-risk developmental drilling opportunities with predictable production profiles. They provide a high degree of capital flexibility through commodity cycles.

• Substantial inventory of low-cost, low-risk and high-return development opportunities. We expect our locations to generate highly attractive rates of return. For example, our inventory includes 790 gross (786 net) identified drilling locations associated with proved undeveloped reserves with projected average single-well rates of return of approximately 40%, based on our assumptions used in preparing our November 30, 2017 reserve report, and approximately 1,305 gross (1,300 net) additional identified drilling locations with economics that management believes are similar to those of our proved undeveloped locations. In addition, we have approximately 3,800 additional identified drilling locations that are currently under review.

• Experienced, principled and disciplined management team. Our management team has significant experience operating and managing oil and gas businesses across numerous domestic and international basins, as well as reservoir and recovery types. We will employ our deep technical, operational and strategic management experience to optimize the value of our assets and the Company. We are focused on the principles of growing cash flows and the value of our production and reserves and take a disciplined approach to development and operating cost management, field development efficiencies and the application of proven technologies and processes new to our properties in order to generate a sustained cost advantage. We believe that our knowledge and operating experience, together with the quality of our assets, offer opportunities to increase value and that our value-driven approach to operational and strategic decisions will help us optimize our returns.

• Substantial capital flexibility derived from a high degree of operational control and stable cost environment. We operate over 95% of our productive wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, approximately 76% of our acreage is held by production, including 99% of our acreage in California. Our high degree of operational control over our properties, together with the large portion of our acreage that is held by production, gives us flexibility over the execution of our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production. Our lack of need for advanced equipment in our key operations and the stable cost of the service environment drive substantially lower service costs and provide relative insulation from the cost inflation pressures experienced by our peers who operate primarily in unconventional plays. The more stable costs associated with our operations provide us significant visibility and understanding of our expected cash flows, which allow us to manage our business through commodity price cycles.

• Conservative balance sheet leverage with ample liquidity and minimal contractual obligations. After giving effect to this offering and repayment of borrowings under the RBL Facility (as defined herein), we expect to have approximately $ million of available liquidity, defined as cash on hand plus availability under our RBL Facility. In addition, we have minimal long-term service or fixed-volume delivery commitments. This liquidity and flexibility permit us to capitalize on opportunities that may arise to grow and increase stockholder value.

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• Brent-influenced pricing advantage. California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources. There is a closer correlation of prices in California to Brent pricing than to WTI. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.

Our Business Strategy

The principal elements of our business strategy include the following:

• Grow production and reserves in a capital efficient manner using internally generated cash flow. We intend to allocate capital in a disciplined manner to projects that will produce predictable and attractive rates of return. We plan to direct capital to our oil-rich and low-risk development opportunities while focusing on driving cost efficiencies across our asset base with the primary objective of internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins.

• Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we intend to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will explore innovative EOR techniques to unlock additional value and have allocated capital towards next generation technologies. For example, in our South Belridge Hill non-thermal and Midway-Sunset thermal diatomite properties, we employ both fracture stimulation and advanced thermal techniques, and in our Piceance properties, we use advanced proppant-less slick water fracture stimulation techniques. In addition, we intend to expand our geologic investigation of deeper reservoirs on our acreage and adjacent acreage below existing producing reservoirs and to expand strategic development beyond our known productive areas.

• Proactively and collaboratively engage in matters related to regulation, safety, environmental and community relations. We are committed to proactive engagement with regulatory agencies in order to realize the full potential of our resources in a timely fashion that safeguards people and the environment and complies with law and regulations. We expect our work with regulators and legislators throughout the rule making process to minimize any adverse impact that new legislation and regulations might have on our ability to maximize our resources. We have found constructive dialogue with regulatory agencies can help avert compliance issues.

• Maintain balance sheet strength and flexibility through commodity price cycles. We intend to fund our capital program primarily through the use of internally generated levered free cash flow from operations. Over time, we expect to de-lever through organic growth and with excess levered free cash flow. Our objective is to achieve and maintain a long-term, through-cycle leverage ratio between 1.5x and 2.0x.

• Enhance future cash flow stability and visibility through an active and continuous hedging program. Our hedging strategy is designed to insulate our capital program from price fluctuations by securing price realizations and cash flows, including fixed-price gas purchase agreements and other hedging contracts. We have protected a portion of our anticipated production through 2020 as part of our crude oil hedging program. As of January 4, 2018, we have hedged approximately 6.4 MMBbls for 2018, 5.0 MMBbls for 2019 and 0.4 MMBbls for 2020 of crude oil production. We will review our hedging program continuously as conditions change.

Operational Overview

We generally seek to be the operator of our properties so that we can develop and implement drilling programs and optimization projects that not only replace production, but add value through reserve and

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production growth and future operational synergies. Many of our properties have long histories of successful development. Additional opportunities exist to continue using successful development techniques while also embracing new incremental recovery technologies. The long-lived nature of our properties allows us to continually seek operational efficiencies to enhance value creation through all operational phases.

Thermal Recovery

Most of our assets in California consist of heavy crude oil, which requires heat, supplied in the form of steam, injected into the oil producing formations to reduce the oil viscosity, thereby allowing the oil to flow to the wellbore for production. We utilize steamflooding on these assets and have not yet begun to use additional tertiary methods to further produce oil from our reserves. We have cyclic and continuous steam injection projects in the San Joaquin and Ventura basins, primarily in Kern County and in fields such as Midway-Sunset, Poso Creek, McKittrick, South Belridge and Placerita, with demonstrated internal and third party results across thousands of wells. Historically, we start production from heavy oil reservoirs with cyclic injection and then expand operations to include continuous injection in adjacent wells. We intend to continue employing both recovery techniques as long as a favorable oil to gas price spread exists. Full development of these projects typically takes multiple years and involves upfront infrastructure construction for steam and water processing facilities and follow on development drilling. These steam injection projects are generally shallower in depth (300 to 1,200 ft) than our other programs and the wells are relatively inexpensive to drill at approximately $375,000 per well. Therefore, we can normally implement a drilling program quickly with attractive rates of return. For the three months ended September 30, 2017, our total gross average production from thermal recovery projects was 17.4 MBoe/d. We monitor our steam injection closely on each individual project and increase or decrease steam to maximize the value return of each project. As of September 30, 2017, we were injecting over 150,000 barrels of steam daily.

Cogeneration Steam Supply and Conventional Steam Generation

We believe one of the primary methods to keep steam costs low is through the ownership and efficient operation of cogeneration facilities. We own five cogeneration facilities: (i) a 38 MW facility (“Cogen 38”), an 18 MW facility (“Cogen 18”), and two separate 5 MW facilities (“Pan Fee and 21Z CoGens”), each located in the Midway-Sunset Field and (ii) a 42 MW facility (“Cogen 42”) located in the Placerita Field. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine to produce steam and increases the efficiency of the combined process. For more information please see “—Electricity.”

We own 79 fully permitted conventional steam generators. The number of generators operated at any point in time is dependent on the steam volume required to achieve our targeted injection rate and the price of natural gas compared to our oil production rate and the realized price of oil sold. Ownership of these varied steam generation facilities allows for maximum operational control over the steam supply, location and, to some extent, the aggregated cost of steam generation. Our steam supply and flexibility are crucial for the maximization of thermally enhanced heavy oil production in California, cost control and ultimate oil recovery. The natural gas we purchase to generate steam and electricity is primarily based on California price indexes. We pay distribution and transportation charges for the delivery of natural gas to our various locations where we use the natural gas for steam generation purposes. In some cases, this transportation cost is embedded in the price of the natural gas we purchase.

Low Volume Fracture Stimulation

Fracture stimulation is an important and common practice we use to stimulate production of oil and gas. The process involves injection of water, sand and trace chemicals under pressure into underground oil and gas bearing rock formations to create or enlarge fractures and stimulate the flow of oil and gas into the oil and gas production well. Our California fracture stimulation projects use significantly lower fluid volumes than is typical in other areas. For example, we expect to use approximately 144,000 gallons of water per well for our Hill fracture

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stimulations compared to a median of nearly 4 million gallons for horizontal wells fractured in the United States in 2015. Similarly, we expect to use only about 324,000 pounds of sand per Hill well compared to a nationwide average of over 4 million pounds of sand per well in 2015. We use this method of reservoir stimulation in the San Joaquin basin to stimulate our non-thermal Diatomite reservoir at the Hill property. In the first nine months of 2017, we did not spend capital on this method of reservoir stimulation. We plan to apply this technique in 2018 and beyond on our inventory of Hill non-thermal Diatomite development wells. We use more traditional fracture stimulation to complete our wells in the Piceance basin. In this area, we use “proppant-less stimulation” to stimulate the reservoir with water and no proppant. In the first nine months of 2017, we did not spend capital on this method of reservoir stimulation. We plan to apply this technique, which has increased both initial rates and EURs versus previous stimulation methods, in 2018 and beyond on our inventory of Piceance development wells.

Our Midstream Infrastructure

We own a network of oil and gas gathering lines across our assets, and our oil and natural gas is transported through such lines and third-party gathering systems and pipelines. When moving through the third-party systems, we incur processing, gathering and transportation expenses to move our oil and natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume, distance shipped and the fee charged by the third-party processor or transporter.

We also own a natural gas processing plant with capacity of approximately 30 MMcf/d in the Brundage Canyon area, located in Duchesne County, Utah. This facility takes delivery from gathering and compressions facilities we operate. Approximately 95% of the gas gathered at these facilities is produced from wells that we operate. The system gathers and dehydrates the product, removes, collects and sells condensate and compresses the gas to sales pressures in six central compressors. The gas then goes to our plant which provides refrigerated liquid recovery to a negative 20 degrees Fahrenheit. The NGLs recovered are trucked to third party facilities for fractionation and delivery to market. Current throughput at the processing plant is 18 to 20 MMcf/d and sufficient capacity remains for additional large scale development drilling.

Marketing Arrangements

We market crude oil, natural gas, NGLs and electricity.

Crude Oil. Approximately 75% of our California crude oil production is connected to California markets via crude oil pipelines. We generally do not transport, refine or process the crude oil we produce and do not have any long-term crude oil transportation arrangements in place. California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources. This dynamic has led to periods where the price for the primary benchmark, Midway-Sunset, a 13° API heavy crude, has been equal to or exceeded the price for WTI, a light 40° API crude. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low transportation costs, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California. Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to purchaser-posted prices for the producing area. As of December 31, 2016, all of our oil production was sold under short-term contracts. The waxy quality of oil in Utah has historically limited sales primarily to the Salt Lake City market, which is largely dependent on the supply and demand of oil in the area. Export options to other markets via rail are available and have been used in the past, but are comparatively expensive.

Natural Gas. Our natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area. Our natural gas production is sold to purchasers under seasonal spot price or index contracts. Although exact percentages vary daily, as of December 31, 2016, all of our natural gas and NGLs production was sold under short-term contracts at market-sensitive or spot prices. In certain circumstances, we have entered into natural gas processing contracts whereby the residual natural gas is sold under short-term contracts but the related NGLs are sold under long-term contracts. In all such cases, the residual natural gas and NGLs are sold at market-sensitive index prices.

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NGLs. We do not have long-term or long-haul interstate NGLs transportation agreements. We sell substantially all of our NGLs to third parties using market based pricing. Our NGL sales are generally pursuant to processing contracts or short-term sales contracts. The relatively small volumes of condensate produced in Texas and Colorado are sold under market-based short-term contracts.

Electricity. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce field operating costs, a significant share is sold into the California market. Excess electric output and associated electric products are marketed to third parties and offered daily into the California electric market to be dispatched based on pricing and grid requirements.

Electricity

Generation. Our cogeneration facilities generate both electricity and steam for our properties and electricity for off lease sales. The total average electrical generation capacity of three of our five cogeneration facilities, which are centrally located on certain of our oil producing properties, was approximately 90 MW for the year ended December 31, 2016. Our other two, and newest, cogeneration facilities came on line in the third quarter of 2017. The steam generated by each facility is capable of being delivered to numerous wells that require steam for our EOR processes. The main purpose of the cogeneration facilities is to reduce the steam costs in our heavy oil operations and to secure operating control of our steam generation. Expenses of operating the cogeneration plants are analyzed regularly to determine whether they are advantageous versus conventional steam generators.

Cogeneration costs are allocated between electricity generation and oil and natural gas operations based on the conversion efficiency (of fuel to electricity and steam) of each cogeneration facility and certain direct costs to produce steam. Cogeneration costs allocated to electricity will vary based on, among other factors, the thermal efficiency of our cogeneration plants, the price of natural gas used for fuel in generating electricity and steam, and the terms of our power contracts.

Sales Contracts. We sell electricity produced by three of our cogeneration facilities under long-term contracts approved by the California Public Utilities Commission (the “CPUC”) to two California investor owned utilities, Southern California Edison Company (“Edison”) and Pacific Gas and Electric Company (“PG&E”). The following summarizes the contracts for the three facilities.

• Cogen 18 facility: Our Public Utilities Regulatory Policy Act of 1978, as amended (“PURPA”), PPA with PG&E became effective on October 1, 2012, and has a term of seven years. Because the rated capacity of our Cogen 18 facility is less than 20 MW, it continues to be eligible for PPAs pursuant to PURPA. Under such PPA, we are paid the CPUC-determined short run avoidance cost energy price and a combination of firm and “as-available” capacity payments.

• Cogen 42 facility: Pursuant to a competitive solicitation, our request for offers (“RFO”) PPA with Edison became effective on July 1, 2014, and has a term of seven years. Under such PPA, we are paid a negotiated energy and capacity price stipulated in the contract.

• Cogen 38 facility: Our legacy PPA expired in March 2012, at which time a transition PPA with PG&E became effective. We participated in a competitive solicitation, which resulted in the execution of a RFO PPA with Edison that became effective on July 1, 2015, and has a term of seven years. Under such PPA, we are paid a negotiated energy and capacity price stipulated in the contract.

Electricity and steam produced from our Pan Fee and 21Z CoGens facilities, are used solely for field operations. For more information, see “Risk Factors—Risks Related to Our Business and Industry—We are dependent on our cogeneration facilities and deteriorations in the electricity market and regulatory changes in California may materially and adversely affect our financial condition, results of operations and cash flows.”

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The following table sets forth information regarding our cogeneration facilities and contracts for the year ended December 31, 2016:

Facility

Type of Contract

Purchaser

Contract Expiration

Approximate MW Available for Sale

Approximate MW Consumed in Operations

Approximate Barrels of Steam Per Day in 2016

Cogen 18

PURPA

PG&E

Sept. 2019

10

6

6,665

Cogen 42

RFO

Edison

June 2021

34

3

12,607

Cogen 38

RFO

Edison

June 2022

35

1

14,255

Principal Customers

For the year ended December 31, 2016, Tesoro Corporation and Phillips 66 accounted for approximately 34% and 28%, respectively, of our oil, natural gas and NGL sales. For the year ended December 31, 2015, Tesoro Corporation, Phillips 66 and Exxon Mobil Corporation accounted for approximately 24%, 23% and 20%, respectively, of our oil, natural gas and NGL sales. For the nine months ended September 30, 2017 and for the years ended December 31, 2016 and 2015, 100% of electricity sales were attributable to PG&E and Edison.

At December 31, 2016, trade accounts receivable from two customers represented approximately 29% and 21% of our receivables. At December 31, 2015, trade accounts receivable from three customers represented approximately 24%, 22% and 11% of our receivables.

If we were to lose any one of our major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser’s service area and it could have a detrimental effect on the prices and volumes of oil, natural gas and NGLs that we are able to sell.

Our Reserves and Production Information

Reserve Data

The following table summarizes our estimated proved reserves and related PV-10 at November 30, 2017. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton. The reserve estimates were prepared in accordance with current SEC rules and regulations regarding oil, natural gas and NGL reserve reporting. Reserves are stated net of applicable royalties.

	At November 30, 2017(1)
	San Joaquin and Ventura basins		Uinta basin		Piceance basin		East Texas basin		Total
Proved developed reserves:
Oil (MMBbl)		62		7		—		—		69
Natural Gas (Bcf)		—		47		43		12		101
NGLs (MMBbl)		—		1		—		—		1
Total (MMBoe)(2)(3)		62		16		7		2		87
Proved undeveloped reserves:
Oil (MMBbl)		32		—		—		—		32
Natural Gas (Bcf)		—		—		137		—		137
NGLs (MMBbl)		—		—		—		—		—
Total (MMBoe)(3)		32		—		23		—		55
Total proved reserves:
Oil (MMBbl)		93		7		—		—		101
Natural Gas (Bcf)		—		47		179		12		238
NGLs (MMBbl)		—		1		—		—		1
Total (MMBoe)(3)		93		16		30		2		142
PV-10 ($MM)		952		82		27		8		1,069

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(1) Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $53.40 per Bbl ICE (Brent) for oil and NGLs and $3.01 per MMBtu NYMEX Henry Hub for natural gas at November 30, 2017. Prices were calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For more information regarding commodity price risk, please see “Risk Factors—Risks Related to Our Business and Industry—Oil, natural gas and NGL prices are volatile.”

(2) Approximately 9% of proved developed oil reserves, 1% of proved developed NGLs reserves, 0% of proved developed natural gas reserves and 7% of total proved developed reserves are non-producing.

(3) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the nine months ended September 30, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $52.59 per Bbl and $3.17 per Mcf, respectively, resulting in an oil-to-gas ratio of over 16 to 1.

PV-10

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

With respect to PV-10 calculated as of November 30, 2017, it is not practical to calculate the taxes for such period because GAAP does not provide for disclosure of standardized measure on an interim basis.

Proved Undeveloped Reserves Additions

From January 1, 2017 to November 30, 2017, we had proved undeveloped reserve additions of 42 MMBoe from extensions and discoveries. As of December 31, 2016, we had minimal proved undeveloped reserves due to the Chapter 11 Proceeding. Additions of proved undeveloped reserves reflect an increase from that minimal amount. In the third quarter of 2017, we completed the Hill Acquisition and the Hugoton Disposition. The Hill Acquisition accounted for an increase of 13 MMBoe of proved undeveloped reserves. The Hugoton Disposition did not affect our proved undeveloped reserves. The total changes to our proved undeveloped reserves from December 31, 2016 to November 30, 2017 were as follows:

	San Joaquin and Ventura basins		Uinta basin		Piceance basin		East Texas basin		Hugoton basin		Total
Beginning balance at December 31, 2016 (MMBoe)(1)		—		—		—		—		—		—
Production (MMBoe)(1)		—		—		—		—		—		—
Revisions or reclassifications of previous estimates (MMBoe)(1)		—		—		—		—		—		—
Improved Recovery (MMBoe)(1)		—		—		—		—		—		—
Extensions and Discoveries (MMBoe)(1)		18		—		23		—		—		42
Purchases (MMBoe)(1)		13		—		—		—		—		13
Sales (MMBoe)(1)		—		—		—		—		—		—
Ending balance as of November 30, 2017 (MMBoe)(1)		32		—		23		—		—		55

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(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the nine months ended September 30, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $52.59 per Bbl and $3.17 per Mcf, respectively, resulting in an oil-to-gas ratio of over 16 to 1.

Extensions and Discoveries

Through 2017 we added 42 MMBoe of proved reserves from extensions and discoveries split between California and Colorado, supported by our recent development activity in both regions. This is up from the 0 MMBoe represented in the December 31, 2016 reserves report which was due to LINN Energy’s decision not to commit capital to the development of the fields at that time.

Reserves Evaluation and Review Process

Independent engineers, DeGolyer and MacNaughton, prepared our reserve estimates reported herein. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by us. When preparing the reserve estimates, the independent engineering firm did not independently verify the accuracy and completeness of the information and data furnished by us with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention that brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their related questions. The estimates of reserves conform to SEC guidelines, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost, operating expense and realized commodity revenue data.

The independent engineering firm also prepared estimates with respect to reserve categorization, using the definitions of proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

Our internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of our reserve estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by Kurt Neher, who has a Masters in Geology from the University of South Carolina and a Bachelors in Geology from Carleton College, and more than 31 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval expected by our Board of Directors. We have not filed reserve estimates with any federal authority or agency.

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Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured exactly. For more information, see “Risk Factors—Risks Related to Our Business and Industry—Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.”

Determination of Identified Drilling Locations

Proven Drilling Locations

Based on our reserves report as of November 30, 2017, we have 790 gross (786 net) drilling locations attributable to our proved undeveloped reserves. We use production data and experience gained from our development programs to identify and prioritize this proven drilling inventory. These drilling locations are included in our inventory only after they have been evaluated technically and are deemed to have a high likelihood of being drilled within a five year time frame. As a result of technical evaluation of geologic and engineering data, it can be estimated with reasonable certainty that reserves from these locations will be commercially recoverable in accordance with SEC guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local regulations and other factors it deems relevant in determining such locations.

Unproven Drilling Locations

We have also identified a multi-year inventory of 5,190 gross (4,814 net) drilling locations that are not associated with proved undeveloped reserves but are specifically identified on a field by field basis considering the applicable geologic, engineering and production data. We analyze past field development practices and identify analogous drilling opportunities taking into consideration historical production performance, estimated drilling and completion costs, spacing and other performance factors. These drilling locations primarily include (i) infill drilling locations, (ii) additional locations due to field extensions or (iii) potential IOR and EOR project expansions, some of which are currently in the pilot phase across our properties, but have yet to be moved to the proven category. We believe the assumptions and data used to estimate these drilling locations are consistent with established industry practices based on the type of recovery process we are using.

We plan to analyze our acreage for exploration drilling opportunities at appropriate levels. We expect to use internally generated information and proprietary models consisting of data from analog plays, 3-D seismic data, open hole and mud log data, cores and reservoir engineering data to help define the extent of the targeted intervals and the potential ability of such intervals to produce commercial quantities of hydrocarbons.

Well Spacing Determination

Our well spacing determinations in the above categories of identified well locations are based on actual operational spacing within our existing producing fields, which we believe are reasonable for the particular recovery process employed (i.e., primary, waterflood and EOR). Spacing intervals can vary between various reservoirs and recovery techniques. Our development spacing can be less than one acre for a thermal steamflood development in California and greater than ten acres for a primary gas expansion development in our Piceance asset in Colorado.

Drilling Schedule

Our identified drilling locations have been scheduled as part of our current multi-year drilling schedule or are expected to be scheduled in the future. However, we may not drill our identified sites at the times scheduled or at all. We view the risk profile for our prospective drilling locations and any exploration drilling locations we may identify in the future as being higher than for our other proved drilling locations.

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Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals, available transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. For a discussion of the risks associated with our drilling program, see “Risk Factors—Risks Related to Our Business and Industry—We may not drill our identified sites at the times we scheduled or at all.”

The table below sets forth our total identified drilling locations as of November 30, 2017.

	Proven Drilling Locations (Gross)				Total Identified Drilling Locations (Gross)
	Oil and Natural Gas Wells		Injection Wells		Oil and Natural Gas Wells		Injection Wells
San Joaquin and Ventura basins		549		161		2,842		900
Uinta basin		—		—		1,246		—
Piceance basin		80		—		869		—
East Texas basin		—		—		123		—
Total Identified Drilling Locations		629		161		5,080		900

Production and Operating Data

The following table sets forth information regarding production, realized and benchmark prices, and production costs (i) on a historical basis for the years ended December 31, 2016 and 2015, for the two months ended February 28, 2017 and the seven months ended September 30, 2017 and (ii) on a pro forma basis for the nine months ended September 30, 2017.

The pro forma information has been prepared to give pro forma effect to (i) the Plan and related transactions and fresh-start accounting and (ii) the Hugoton Disposition, as if each had been completed as of January 1, 2016, respectively. The summary unaudited pro forma financial information does not give effect to the Hill Acquisition because such transaction is not deemed significant under Rule 3-05 of the SEC’s Regulation S-X, so it is not required to be presented herein. For more information, see “Prospectus Summary—Summary Historical and Pro Forma Financial Information.”

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For additional information regarding pricing dynamics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Environment and Market Conditions.”

	Pro Forma(5)			Berry Corp.			Berry LLC
	Nine Months Ended September 30, 2017			Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016			Year Ended December 31,
													2016			2015
Production Data:
Oil (MBbl/d)		19.9			20.0			19.5			23.9			23.1			30.0
Natural gas (MMcf/d)		31.1			57.2			71.7			78.6			78.1			92.7
NGLs (MBbl/d)		0.6			2.6			5.2			3.7			3.6			2.9
Average daily combined production (MBoe/d)(1)		25.7			32.2			36.6			40.7			39.7			48.4
Total combined production (MBoe)(1)		7,018			6,880			2,162			11,160			14,533			17,666
Average realized prices(2):
Oil (per Bbl)	$	45.31		$	44.86		$	46.94		$	34.00		$	35.83		$	42.27
Natural gas (per Mcf)	$	2.85		$	2.69		$	3.42		$	2.15		$	2.31		$	2.66
NGLs (per Bbl)	$	17.67		$	21.67		$	18.20		$	16.08		$	17.67		$	20.27
Average Benchmark prices:
ICE (Brent) oil ($/Bbl)	$	52.59		$	51.70		$	55.72		$	42.97		$	45.00		$	53.64
NYMEX Henry Hub natural gas ($/Mcf)	$	3.17		$	3.03		$	3.66		$	2.29		$	2.46		$	2.66
Average costs per Boe(3):
Lease operating expenses	$	18.65		$	15.81		$	13.06		$	12.42		$	12.73		$	13.88
Electricity generation expenses	$	1.91		$	1.48		$	1.48		$	1.09		$	1.18		$	1.02
Electricity sales	$	(2.73	)	$	(2.26	)	$	(1.69	)	$	(1.57	)	$	(1.60	)	$	(1.39	)
Transportation expenses	$	2.11		$	2.71		$	2.86		$	2.91		$	2.86		$	2.95
Marketing expenses	$	0.33		$	0.24		$	0.30		$	0.19		$	0.21		$	0.22
Marketing revenues	$	(0.36	)	$	(0.28	)	$	(0.29	)	$	(0.25	)	$	(0.25	)	$	(0.32	)
Taxes, other than income taxes	$	3.63		$	3.65		$	2.41		$	1.85		$	1.73		$	4.00
General and Administrative Expenses(4)	$	6.62		$	5.78		$	3.68		$	5.85		$	5.45		$	4.87
Depreciation, depletion and amortization	$	7.94		$	7.03		$	13.02		$	12.54		$	12.26		$	14.23

(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the nine months ended September 30, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $52.59 per Bbl and $3.17 per Mcf, respectively, resulting in an oil-to-gas ratio of over 16 to 1.

(2) Does not include the effect of gains (losses) on derivatives.

(3) We report electricity and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold

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externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties.

(4) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $28.3 million for the seven and nine months ended September 30, 2017.

(5) Does not include the effects of the Hill Acquisition. We estimate that the production associated with the Hill asset for the nine months ended September 30, 2017 was approximately 3,000 Boe/d.

The following tables sets forth information regarding production volumes for fields with greater than 15% of our total proved reserves for each of the periods indicated:

	Year Ended December 31,
	2016		2015
Hugoton basin Field
Total production:
Oil (MBbls)		—		—
Natural gas (Bcf)		14.6		16.8
NGL (MBbls)		1,020		814
Total (MBoe)(1)		3,457		3,619

(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the nine months ended September 30, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $52.59 per Bbl and $3.17 per Mcf, respectively, resulting in an oil-to-gas ratio of over 16 to 1.

	Year Ended December 31,
	2016		2015
SJV South Midway Field
Total production:
Oil (MBbls)		2,477		2,598
Natural gas (Bcf)		—		—
NGL (MBbls)		—		—
Total (MBoe)		2,477		2,598

	Year Ended December 31,
	2016		2015
SJV Diatomite Field
Total production:
Oil (MBbls)		*		2,939
Natural gas (Bcf)		*		—
NGL (MBbls)		*		—
Total (MBoe)		*		2,939

* Represented less than 15% of our total proved reserves for the year indicated.

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Productive Wells

As of November 30, 2017, we had a total of 3,721 gross (3,601 net) producing wells (including 469 gross and net steamflood and waterflood injection wells), approximately 90% of which were oil wells. Our average working interests in our producing wells is approximately 95%. Many of our oil wells produce associated gas and some of our gas wells also produce condensate and NGLs.

The following table sets forth our productive oil and natural gas wells (both producing and capable of producing) as of November 30, 2017.

	San Joaquin and Ventura basins		Uinta basin		Piceance basin		East Texas basin		Total
Oil
Gross(1)		2,522		912		—		—		3,434
Net(2)		2,497		867		—		—		3,364
Gas
Gross(1)		—		—		170		117		287
Net(2)		—		—		122		116		238

(1) The total number of wells in which interests are owned. Includes 469 steamflood and waterflood injection wells in California. Excludes eleven wells in the Permian basin all with less than 0.1% working interest and 91 wells in the Piceance basin each with a 5% working interest.

(2) The sum of fractional interests.

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of November 30, 2017. Approximately 76% of our leased acreage was held by production at November 30, 2017.

	San Joaquin and Ventura basins		Uinta basin		Piceance basin		East Texas basin		Total
	(in thousands)
Developed(1)
Gross(2)		10,800		93,763		9,260		5,853		119,676
Net(3)		7,865		70,990		6,780		4,533		90,168
Undeveloped(4)
Gross(2)		80		49,357		1,293		—		50,730
Net(3)		80		27,815		1,228		—		29,123

(1) Acres spaced or assigned to productive wells.

(2) Total acres in which we hold an interest.

(3) Sum of fractional interests owned based on working interests or interests under arrangements similar to production sharing contracts.

(4) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the acreage contains proved reserves.

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Participation in Wells Being Drilled

The following table sets forth our participation in wells being drilled as of November 30, 2017.

	San Joaquin and Ventura basins		Uinta basin		Piceance basin		East Texas basin		Total
Development wells
Gross		2		—		—		—		2
Net		2		—		—		—		2
Exploratory wells
Gross		—		—		—		—		—
Net		—		—		—		—		—

At November 30, 2017, we were participating in 14 steamflood and waterflood pressure maintenance projects. Twelve steamflood projects and one waterflood project was located in the San Joaquin basin, and one waterflood project was located in the Uinta basin.

Drilling Activity

The following table shows the net development wells we drilled during the periods indicated. We did not drill any exploratory wells during the periods presented. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

	San Joaquin and Ventura basins			Uinta basin		Piceance basin		East Texas basin		Total
Eleven months ended November 30, 2017
Oil		111	(1)		—		—		—		111	(1)
Natural Gas		—			—		—		—		—
Dry		—			—		—		—		—
2016
Oil		11	(1)		—		—		—		11
Natural Gas		—			—		—		—		—
Dry		—			—		—		—		—
2015
Oil		120	(1)		1		—		—		121	(1)
Natural Gas		—			—		11		—		11
Dry		—			—		—		—		—

(1) Includes injector wells.

Delivery Commitments

We have made commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. For oil, these commitments are limited to lease production and do not have set volumes. As of November 30, 2017, 17,359 MMBtu/d of gas were contracted to be delivered under gas contracts with fixed volumes including 5,000 MMBtu/d in Texas and 12,359 MMBtu/d in Utah. None of these commitments in any given year is expected to have a material impact on our financial statements.

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Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties at the time of acquisition. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. We do not commence drilling operations on a property until we have cured known title defects on such property that are material to the project. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations, or net profits interests.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and master limited partnerships in acquiring properties, contracting for drilling and other related services, and securing trained personnel. We also are affected by competition for drilling rigs 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 has delayed development drilling and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our drilling program. Unlike a typical resource play, the lower-cost, commoditized nature of our equipment and service providers allows for relative insulation from the cost inflation pressures experienced by producers in unconventional plays. For more information regarding competition and the related risks in the oil and natural gas industry, please see “Risk Factors—Risks Related to Our Business and Industry—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.”

Operating Hazards and Insurance

The oil and natural gas industry involves a variety of operating hazards and risks that could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, and suspension of operations. We may be liable for environmental damages caused by previous owners of property we purchase and lease. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds otherwise available, or result in the loss of properties. In addition, we may participate in wells on a nonoperated basis and therefore may be limited in our ability to control the risks associated with the operation of such wells.

In accordance with customary industry practices, we maintain insurance against some, but not all, potential losses. We cannot provide assurance that any insurance we obtain will be adequate to cover our losses or liabilities. We have elected to self-insure for certain items for which we have determined that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. For more information about potential risks that could affect us, see “Risk Factors—Risks Related to Our Business and Industry—We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.”

Seasonality

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities. These seasonal conditions can occasionally pose challenges in our Utah and Colorado operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages

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and increase costs or delay operations. For example, our operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires.

Regulation of Health, Safety and Environmental Matters

Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the oil and natural gas industry. These laws and regulations may:

• require the acquisition of various permits before drilling commences;

• require notice to stakeholders of proposed and ongoing operations;

• require the installation of expensive pollution control equipment;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on lands located within wilderness, wetlands, areas inhabited by endangered species and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources;

• require remedial measures to prevent pollution from former operations, such as pit closure, reclamation and plugging and abandonment of wells;

• impose substantial liabilities for pollution resulting from operations or for preexisting environmental conditions on our properties; and

• require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.

For example, in 2014, the Division of Oil, Gas, and Geothermal Resources of the California Department of Conservation (“DOGGR”) began a detailed review of the multi-decade practice of permitting underground injection wells under the Safe Drinking Water Act (“SDWA”). The purpose of the review is to ensure that wastewater is not injected into formations that could be a future source of drinking water supply. Pending the outcome of the review, DOGGR has restricted injection in certain formations or from wells in designated fields, though the agency will approve exemptions from the restrictions upon request. Currently we have exemption requests pending for three fields: Poso Creek, McKittrick and Midway Sunset. We anticipate that these three requests will be approved in 2018, with the first approval expected to come for our Poso Creek operations. To date, the restrictions have not affected our oil and natural gas production in any material way. However, DOGGR or other government authorities could ultimately restrict injection of produced water or other fluids in additional formations or certain wells or take other administrative actions.

These laws, rules and regulations may also restrict the production rate of oil, natural gas and NGL below the rate that would otherwise be possible. The regulatory burden on the industry increases the cost of doing business and consequently may have an adverse effect upon capital expenditures, earnings or competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on operating costs.

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The environmental laws and regulations applicable to us and our operations include, among others, the following U.S. federal laws and regulations:

• CAA, which governs air emissions;

• Clean Water Act (“CWA”), which governs discharges to and excavations within the waters of the United States;

• Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous substances have been released into the environment (commonly known as “Superfund”);

• The Oil Pollution Act of 1990, which amends and augments the CWA and imposes certain duties and liabilities related to the prevention of oil spills and damages resulting from such spills;

• Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures;

• National Environmental Policy Act (“NEPA”), which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands;

• Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste;

• SDWA, which governs the underground injection and disposal of wastewater; and

• U.S. Department of Interior regulations, which regulate oil and gas production activities on federal lands and impose liability for pollution cleanup and damages.

Various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGL, including imposing production taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of resources. States may regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulations, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGL that may be produced from our wells and to limit the number of wells or locations we can drill. The oil and natural gas industry is also 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 opportunity employment.

We believe that compliance with currently applicable environmental laws and regulations is unlikely to have a material adverse impact on our business, financial condition, results of operations or cash flows. Future regulatory issues that could impact us include new rules or legislation relating to the items discussed below.

Climate Change

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHG present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted three sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles, a second that regulates emissions of GHGs from certain large stationary sources under the CAA’s Prevention of Significant Deterioration and Title V permitting programs, and a third that regulates GHG emissions from fossil fuel-burning power plants.

In June 2016, the EPA finalized rules that establish new controls for emissions of methane (a GHG considered more potent than carbon dioxide) from new, modified or reconstructed sources in the oil and natural

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gas source category, including production, processing, transmission and storage activities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore oil and natural gas production facilities, on an annual basis. In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in 2017 the Trump administration indicated that the United States would be withdrawing from participation in the Paris Agreement. Legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the United States. At the state level, almost one half of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs, including by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. See “—California GHG Regulations” below for additional details on current GHG regulations in the state of California. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce.

Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. For more information, please see “Risk Factors—Risks Related to Our Business and Industry—Concerns about climate change and other air quality issues may affect our operations or results;” and “—Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy.”

California GHG Regulations

In October 2006, California adopted the Global Warming Solutions Act of 2006, which established a statewide “cap and trade” program with an enforceable compliance obligation beginning with 2013 GHG emissions and ending in 2020. In July 2017, California extended its cap and trade program through 2030. The program is designed to reduce the state’s GHG emissions to 1990 levels by 2020 and to reduce the state’s GHG emissions to at least 40% below 1990 levels by 2030. The California cap and trade program sets maximum limits or caps on total emissions of GHGs from industrial sectors of which we are a part, as our California operations emit GHGs. The cap will decline annually through 2030. We are required to remit compliance instruments for each metric ton of GHG that we emit, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. Under the cap and trade program, we will be granted a certain number of California carbon allowances (“CCA”) and we will need to purchase CCAs and/or offset credits to cover the remaining amount of our emissions. Compliance with the California cap and trade program laws and regulations could significantly increase our capital, compliance and operating costs and could also reduce demand for the oil and natural gas we produce. The cost to acquire compliance instruments will depend on the market price for such instruments at the time they are purchased, the distribution of cost-free allowances among various industry sectors by the California Air Resources Board and our ability to limit our GHG emissions and implement cost-containment measures.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under

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pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. However, in May 2014, the EPA announced an advance notice of proposed rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and natural gas exploration or production. Further, in March 2015, the Department of the Interior’s Bureau of Land Management (“BLM”) adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for well-bore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. Implementation of the BLM rule has been suspended pending the outcome of several lawsuits filed to challenge the rule, and the Trump Administration recently indicated that it intends to withdraw the rule. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.

There may be other attempts to further regulate hydraulic fracturing under the SDWA, the Toxic Substances Control Act and/or other regulatory mechanisms. In December 2016, the EPA released its final report on a wide ranging study on the effects of hydraulic fracturing on water resources. While no widespread impacts from hydraulic fracturing were found, the EPA identified a number of activities and factors that may have increased risk for future impacts. Moreover, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, many states in which we operate have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. In addition, the regulation or prohibition of hydraulic fracturing is the subject of significant political activity in a number of jurisdictions, some of which have resulted in tighter regulation (including, most recently, new regulations in California requiring a permit to conduct well stimulation), bans on fracturing in certain locations, and/or recognition of local government authority to implement such restrictions. Many of these restrictions are being challenged in court cases. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect our revenues, results of operations and net cash provided by operating activities.

We use water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including but not limited to produced water, drilling fluids and other wastes associated with the development or production of natural gas.

The SDWA and the Underground Injection Control (“UIC”) Program

The SDWA and the UIC program promulgated under the SDWA and relevant state laws regulate the drilling and operation of disposal wells that manage produced water (brine wastewater containing salt and other contaminants produced by natural gas and oil wells). The EPA directly administers the UIC program in some states, and in others administration is delegated to the state. Permits must be obtained before developing and using deep injection wells for the disposal of produced water, and well casing integrity monitoring must be conducted periodically to ensure the well casing is not leaking produced water to groundwater. Contamination of groundwater by natural gas and oil drilling, production and related operations may result in fines, penalties, remediation costs and natural resource damages, among other sanctions and liabilities under the SDWA and other federal and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for groundwater contamination, alternative water supplies, property impacts and bodily injury.

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Solid and Hazardous Waste

Although oil and natural gas wastes generally are exempt from regulation as hazardous wastes under the federal RCRA and some comparable state statutes, it is possible some wastes we generate presently or in the future may be subject to regulation under the RCRA or other similar statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including hazardous wastes and there is no guarantee that the EPA or the states will not adopt more stringent requirements in the future. For example, in May 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia that seeks to compel the EPA to review and, if necessary, revise its regulations regarding existing exemptions for exploration and production related wastes. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from designation as hazardous wastes may in the future be designated as hazardous wastes under the RCRA or other similar statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.

In addition, the federal CERCLA can impose joint and several liability without regard to fault or legality of conduct on classes of persons who are statutorily responsible for the release of a hazardous substance into the environment. These persons can include the current and former owners or operators of a site where a release occurs, and anyone who disposes or arranges for the disposal of a hazardous substance released at a site. Under CERCLA, such persons may be subject to strict, joint and several liability for the entire cost of cleaning up hazardous substances that have been released into the environment and for other costs, including response costs, alternative water supplies, damage to natural resources and for the costs of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Each state also has environmental cleanup laws analogous to CERCLA. Petroleum hydrocarbons or wastes may have been previously handled, disposed of, or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. These properties and any materials disposed or released on them may subject us to liability under CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, to contribute to remediation costs, or to perform remedial activities to prevent future environmental harm.

Endangered Species Act

The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered and threatened species or their habitats. Some of our operations may be located in areas that are designated as habitats for endangered or threatened species. In February 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, the U.S. Fish and Wildlife Service continues its effort to make listing decisions and critical habitat designations where necessary for over 250 species, as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. The ESA has not previously had a significant impact on our operations. However, the designation of previously unprotected species as being endangered or threatened could cause us to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.

Air Emissions

In 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. These standards require operators to capture the gas from natural gas well completions and make it available for use or sale, which can be done through the use of “green

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completions.” The standards are applicable to newly fractured wells and existing wells that are refractured, and they also establish specific requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. The EPA amended these rules in December 2014 to specify requirements for different flowback stages and to expand the rules to cover more storage vessels, among other changes.

Our costs for environmental compliance may increase in the future based on new environmental regulations. In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands. Implementation of the BLM rules has been temporarily suspended by the Trump Administration, but several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. The EPA has also adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant.

NEPA

Oil and natural gas exploration and production activities on federal lands are subject to NEPA. NEPA requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

Water Resources

The CWA and analogous state laws restrict the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined to include, among other things, certain wetlands. Under the CWA, permits must be obtained for the discharge of pollutants into waters of the United States. The CWA provides for administrative, civil and criminal penalties for unauthorized discharges, both routine and accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated with construction activities. Pursuant to these laws and regulations, we may be required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The CWA also prohibits the discharge of fill materials to regulated waters including wetlands without a permit from the U.S. Army Corps of Engineers. Also, in August 2016, the EPA finalized new wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works.

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Natural Gas Sales and Transportation

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company, but the status of these lines has never been challenged before FERC. The distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change based on future determinations by FERC, the courts, or Congress, and application of existing FERC policies to individual factual circumstances. Accordingly, the classification and regulation of some of our natural gas gathering facilities may be subject to challenge before FERC or subject to change based on future determinations by FERC, the courts, or Congress. In the event our gathering facilities are reclassified to FERC-regulated transmission services, we may be required to charge lower rates and our revenues could thereby be reduced.

FERC requires certain participants in the natural gas market, including natural gas gatherers and marketers which engage in a minimum level of natural gas sales or purchases, to submit annual reports regarding those transactions to FERC. Should we fail to comply with this requirement or any other applicable FERC-administered statute, rule, regulation or order, it could be subject to substantial penalties and fines.

Federal Energy Regulation

The enactment of the PURPA and the adoption of regulations thereunder by the FERC provided incentives for the development of cogeneration facilities such as those we own. A domestic electricity generating project must be a Qualifying Facility (“QF”) under FERC regulations in order to benefit from certain rate and regulatory incentives provided by PURPA.

PURPA provides two primary benefits to QFs. First, QFs and entities that own QFs generally are relieved of compliance with certain federal regulations pursuant to the Public Utility Holding Company Act of 2005. Second, FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility’s avoided cost and that the utility sell back-up power to the QF on a nondiscriminatory basis. The Energy Policy Act of 2005 amended PURPA to allow a utility to petition FERC to be relieved of its obligation to enter into any new contracts with QFs if FERC determines that a competitive wholesale electricity market is available to QFs in the service territory. Effective November 23, 2011, the California utility companies have been relieved of their PURPA obligation to enter into new contracts with cogeneration QFs larger than 20 MW. While the California utility companies are still required to enter into new contracts with smaller facilities, such as our Cogen 18 facility, there is no assurance that we will be able to secure new contracts upon the expiration of the existing contracts for our larger facilities. Even if new contracts are available for our larger facilities, there is no assurance that the prices and terms of such contracts will not adversely affect our financial condition, results of operations and net cash provided by operating activities.

State Energy Regulation

The CPUC has broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in California and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility’s cost structure (generally reflected in its retail rates), power sales agreements between electric utilities and independent electricity producers, such as us, are under the regulatory purview of the CPUC. While we are not subject to direct regulation by the CPUC, the CPUC’s implementation of PURPA and its authority granted to the investor owned utilities to enter into other PPAs are important to us, as is other regulatory oversight provided by the CPUC to the electricity market in California. The CPUC’s implementation of PURPA may be subject to change based on past and future determinations by the courts, or policy determinations made by the CPUC.

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Operations on Indian Lands

A portion of our leases and drill-to-earn arrangements in the Uinta basin operating area and some of our future leases in this and other operating areas may be subject to laws promulgated by an Indian tribe with jurisdiction over such lands. In addition to potential regulation by federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations may apply to lessees, operators and other parties on Indian lands, tribal or allotted. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment and contractor preferences and numerous other matters. Further, lessees and operators on Indian lands may be subject to the jurisdiction of tribal courts, unless there is a specific waiver of sovereign immunity by the relevant tribe allowing resolution of disputes between the tribe and those lessees or operators to occur in federal or state court.

These laws, regulations and other issues present unique risks that may impose additional requirements on our operations, cause delays in obtaining necessary approvals or permits, or result in losses or cancellations of our oil and natural gas leases, which in turn may materially and adversely affect our operations on Indian lands.

Pipeline Safety Regulations

The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, the courts, or Congress may make determinations that affect PHMSA’s regulations or their applicability to our pipelines. These determinations may affect the costs we incur in complying with applicable safety regulations.

Worker Safety

The Occupational Safety and Health Act (“OSHA”) and analogous state laws regulate the protection of the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. In December 2015, the U.S. Departments of Justice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties.

Future Impacts and Current Expenditures

We cannot predict how future environmental laws and regulations may impact our properties or operations. For the year ended December 31, 2016, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2017 or that will otherwise have a material impact on our financial position, results of operations or cash flows.

Legal Proceedings

Substantially all of the Company’s liabilities existing as of May 11, 2016, the petition date for the Company’s Chapter 11 Proceeding, were repaid or restructured under the Plan. Please see “Pro Forma Financial Data—Plan of Reorganization” for more detailed information regarding the Plan and the treatment of claims under the Plan.

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

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For additional information regarding legal proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Lawsuits, Claims, Contingencies and Contractual Obligations.”

Employees

As of January 24, 2018, we had 286 employees. As of December 31, 2016, we had no employees. Prior to our emergence from bankruptcy, the employees of Linn Operating provided services and support to us in accordance with an agency agreement and power of attorney between us and Linn Operating.

Corporate Information

We were incorporated in Delaware in February 2017. Our principal executive offices are located at 5201 Truxtun Ave., Bakersfield, California 93309 and we have additional executive offices located at 16000 N. Dallas Pkwy, Ste 100, Dallas, Texas 75248. Our telephone number is (661) 616-3900 and our web address is www.berrypetroleum.com. Information contained in or accessible through our website is not, and should not be deemed to be, part of this prospectus.

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MANAGEMENT

Executive Officers

The following sets forth information regarding our executive officers as of February 13, 2018:

Name	Age		Position
Arthur T. “Trem” Smith		62	President and Chief Executive Officer, and Director
Cary Baetz		53	Executive Vice President and Chief Financial Officer, and Director
Gary A. Grove		57	Executive Vice President and Chief Operating Officer
Kurt Neher		56	Executive Vice President, Business Development
Kendrick F. Royer		54	Executive Vice President, Corporate Secretary and General Counsel

Arthur T. “Trem” Smith has served as the President, Chief Executive Officer and a director since March 2017. Prior to being named Chief Executive Officer, Mr. Smith began an informal consulting relationship in May 2016, followed by a formal consulting relationship in October 2016, and then served as interim CEO while he was a consultant in January 2017. Mr. Smith has over 35 years of experience in the oil and gas industry. In January 2014, Mr. Smith founded TS&J Consulting, where he served until joining Berry Corp. in March 2017 which focused on providing consulting services to distressed companies and assets in the United States and United Kingdom. From January 2007 until January 2014, Mr. Smith was President and Chief Executive Officer at Hillwood International Energy, L.P. and HKN Energy Ltd., which focused on discoveries and production in the United States and northern Iraq. Mr. Smith spent 25 years of his career at Chevron, from 1981 until 2006, where he served in a number of leadership positions with increasing responsibilities in Russia, Thailand and multiple locations in the United States, including La Habra and San Francisco, California. While at Chevron, Mr. Smith was exposed to all phases of the business, including production, operations, exploration, business development, M&A, finance and technology. Mr. Smith graduated magna cum laude from Amherst College with a major in Geology and Russian and received a Master’s degree and PhD in Economic Geology from Pennsylvania State University.

The board of directors believes Mr. Smith’s knowledge and breadth of experience in all phases of oil and gas exploration and production spanning a career of over 35 years, and strategic management of domestic and international oil and gas assets and operations brings important and valuable skills to the board of directors and us.

Cary Baetz has served as Executive Vice President, Chief Financial Officer and a director since May 2017. Mr. Baetz most recently served as Chief Financial Officer at Seventy Seven Energy Inc., a domestic oilfield services company, from June 2012 to April 2017 and as Treasurer of Seventy Seven Energy Inc. from June 2014 to April 2017. From November 2010 to December 2011, he served as Senior Vice President and Chief Financial Officer of Atrium Companies, Inc. and from August 2008 to September 2010, served as Chief Financial Officer of Boots & Coots International Well Control, Inc. From 2005 to 2008, Mr. Baetz served as Vice President of Finance, Treasurer and Assistant Secretary of Chaparral Steel Company. Prior to joining Chaparral, he had been employed since 1996 with Chaparral’s parent company, Texas Industries Inc. From 2002 to 2005, he served as Director of Corporate Finance of Texas Industries Inc. Mr. Baetz has led the sale of three public companies; has successfully completed two public spin-offs; and raised almost $5 billion in capital. Mr. Baetz holds a Bachelor of Science degree from Oklahoma State University and a Master of Business Administration degree from the University of Arkansas.

The board of directors believes that Mr. Baetz is well-qualified to serve on our board of directors because of his extensive public energy company experience across the financial, strategic planning, investor relations areas and spin-offs.

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Gary A. Grove has served as Executive Vice President and Chief Operating Officer since May 2017. Mr. Grove has over 35 years of experience in the oil and gas industry. Mr. Grove has served as President and Chief Executive Officer of his consulting firm Greyhaven Energy, LLC, from April 2014 to the present, providing strategic planning, technical and acquisition advisory services to oil and gas industry clients. After helping lead Bonanza Creek Energy, Inc. in its initial public offering in 2011, Mr. Grove served as a Director, Executive Vice President, Engineering and Planning and Chief Operating Officer of Bonanza Creek Energy from December 2011 to April 2014. He also served as Director, Executive Vice President and Chief Operating Officer of a number of Bonanza Creek Energy’s predecessor companies from March 2003 to December 2011. Prior to joining the Bonanza Creek entities, Mr. Grove held various reservoir engineering and management positions with UNOCAL and Nuevo Energy. Mr. Grove graduated from Marietta College with a Bachelor of Science degree in Petroleum Engineering.

Kurt Neher has served as our Executive Vice President of Business Development since May 2017. Mr. Neher has over 30 years of diverse technical and commercial experience in the international and United States oil and gas exploration and production business with Shell, Occidental Petroleum (“Oxy”), and California Resources Corporation (“CRC”). Between December 2014 and May 2017, Mr. Neher held the position of Vice President of Business Development at CRC, in which he led the company’s Business Development effort. Prior to joining CRC, Mr. Neher led Oxy’s California-focused exploration team and production geoscience effort from January 2008 to November 2014. From 1994 to 2008, he worked in various roles at Oxy, including as Chief Geologist, Worldwide Exploration Manager and Exploration Vice President, Ecuador. From 1990 to 1994, Mr. Neher held a number of different positions with Shell’s deepwater Gulf of Mexico group in New Orleans. Mr. Neher began his career in 1986 with Shell International in Houston. Mr. Neher has a Masters in Geology from the University of South Carolina and a Bachelors in Geology from Carleton College.

Kendrick F. Royer has served as our Executive Vice President and General Counsel since November 2017 and as Corporate Secretary since December 2017. Prior to joining us, Mr. Royer most recently served as Deputy General Counsel and Assistant Corporate Secretary of CRC, from December 2014 to November 2017. Prior to that he was Assistant General Counsel at Oxy from May 2004 to December 2014. Earlier in his career he served as Senior Vice President, General Counsel and Corporate Secretary at toy retailer FAO, Inc. He started his career with law firms O’Melveny and Myers, LLP and Milbank, Tweed, Hadley and McCloy, LLP. Mr. Royer graduated magna cum laude from Princeton University with a Bachelor of Science in Engineering degree and holds his Juris Doctor from Vanderbilt University Law School.

Board of Directors

The following sets forth information regarding our board of directors as of February 13, 2018:

Name	Age		Position
Arthur T. “Trem” Smith		62	President and Chief Executive Officer, and Director
Cary Baetz		53	Executive Vice President and Chief Financial Officer, and Director
Brent S. Buckley		46	Director (Chairman)
Eugene “Gene” Voiland		71	Director
Kaj Vazales		39	Director

Brent S. Buckley has served as a director since February 20, 2017 and as Chairman of the board since June 19, 2017. Mr. Buckley is a managing director with Benefit Street Partners, one of our principal stockholders, which he joined in September 2014. Prior to joining Benefit Street Partners, from February 2009 through September 2014, Mr. Buckley was engaged in personal business and devoting time to family matters. From March 2006 to February 2009, Mr. Buckley was a managing director at Centerbridge Partners. Prior to Centerbridge, Mr. Buckley worked in various roles at Deutsche Bank Securities and Merrill Lynch. Mr. Buckley received a Master of Arts from the University of Pennsylvania’s Graduate School of Arts & Sciences and a Bachelor of Science from the Wharton School at the University of Pennsylvania.

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The board of directors believes that Mr. Buckley’s management, directorship and business experience and analytical skill in distressed credit and special situation investment activities brings important and valuable skills to the board of directors and us.

Eugene “Gene” Voiland has served as a director since June 19, 2017. Mr. Voiland is Chairman of the Board and of the Audit Committee of Valley Republic Bank where he has served as a member of the bank’s board of directors since 2008, and he also currently works as a management consultant. Mr. Voiland is the retired President and Chief Executive Officer of Aera Energy LLC (“Aera”), where he served for more than 10 years, from 1997 to 2007. He has a long history in the energy industry, having worked over 28 years for Shell before his service at Aera. During his career with Shell, he worked as an engineer and manager throughout the United States. He also held senior management positions with Shell, having been appointed General Manager of Engineering and General Manager of Corporate Planning. Mr. Voiland is a board member of Saltchuk Resources, a transportation company. He is also a board member and past Chairman of the California State Chamber of Commerce. Mr. Voiland is a graduate of Washington State University with a Bachelor of Science in Chemical Engineering. He is a member of the WSU Foundation Board of Governors and the WSU Foundation Investment Committee.

The board of directors believes that Mr. Voiland’s experience in the energy industry, including his experience integrating operations of two separate business cultures to form and run the successful and efficient operations of the Aera joint venture, as well as his experience running two highly regulated businesses in California, together with his prior board experience brings important and valuable skills to the board of directors and us.

Kaj Vazales has served as a director since February 20, 2017. Mr. Vazales serves as a Managing Director in the Distressed Debt group of Oaktree Capital Management, L.P., one of our principal stockholders. He has been a member of the Distressed Debt group since joining Oaktree in 2007. Prior to joining Oaktree, Mr. Vazales served as an analyst in the Financial Restructuring group at Houlihan Lokey, Inc. In addition, Mr. Vazales currently serves on the board of directors of Aleris Corporation and Pulse Electronics (currently serving on the compensation and audit committees). He previously served as a director of Studio City/New Cotai from May 2015 to September 2016. Mr. Vazales received a Bachelor of Arts degree in economics from Harvard University.

The board of directors believes that Mr. Vazales’s extensive financial experience and business acumen in distressed credit as well as his board experience brings important and valuable skills to the board of directors and us.

Board Composition and Director Independence

Pursuant to the Plan, on the Effective Date, we entered into the Stockholders Agreement with members of the Ad Hoc Committee. Under the Stockholders Agreement, the Ad Hoc Committee (referred to in the Stockholders Agreement as the “Stockholder Group”) is required to take all necessary action, including voting in person or by proxy, or executing written consents with respect to, all of their common stock and Series A Preferred Stock of Berry Corp., to cause the following five individuals to be elected as directors of Berry Corp.:

• The individual then serving as Chief Executive Officer of Berry Corp.;

• One individual appointed by Benefit Street Partners (for so long as Benefit Street Partners beneficially owns any common stock or Series A Preferred Stock);

• One individual appointed by Oaktree Capital Management (for so long as Oaktree Capital Management beneficially owns any common stock or Series A Preferred Stock); and

• Two individuals appointed by the Stockholder Group (by approval of a majority of the common stock and Series A Preferred Stock beneficially owned by all members of the Stockholder Group).

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See “Description of Capital Stock—Stockholders Agreement.” The designee of Benefit Street Partners is Brent Buckley. The designee of Oaktree Capital Management is Kaj Vazales. The Stockholder Group also appointed Gene Voiland and Cary Baetz, our Executive Vice President and Chief Financial Officer.

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board to fulfill their duties.

The initial directors will serve for the duration of the term of the Stockholders Agreement. The Stockholders Agreement will terminate automatically upon the occurrence of the third annual meeting of stockholders of Berry Corp. The Stockholders Agreement may be terminated earlier by written agreement of Berry Corp. and the members of the Stockholder Group owning at least a majority of the common stock and Series A Preferred Stock, voting together, then beneficially owned by all members of the Stockholder Group; provided, however, that any early termination also requires the written agreement of any member of the Stockholder Group that then has a right to appoint a director under the Stockholders Agreement.

Committees of the Board of Directors

Audit Committee

Rules implemented by the            and the SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the            and the Exchange Act, subject to transitional relief during the one-year period following the completion of this offering. We will establish an audit committee compliant with            and SEC rules prior to the completion of this offering and expect            will serve as members of such committee. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member.             will satisfy the definition of “audit committee financial expert.”

This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements. We have adopted an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and            listing standards.

Compensation Committee

We have established a compensation committee that consists of            . This committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans. We have adopted a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC, the PCAOB and applicable stock exchange or market standards.

Nominating and Corporate Governance Committee

We expect to establish a nominating and corporate governance committee prior to the completion of this offering. We anticipate that the nominating and corporate governance committee will consist of three directors who will be “independent” under the rules of the SEC, the Sarbanes-Oxley Act and the            listing standards. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes, and maintain a management succession plan. We expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and            listing standards.

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Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Policy and Procedures Governing Related Party Transactions

We intend to adopt a written policy regarding transactions with related parties. See “Certain Relationships and Related Party Transactions—Procedures for Approval of Related Party Transactions.”

Code of Business Conduct and Ethics

Our board of directors has adopted a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the            . Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the            .

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EXECUTIVE COMPENSATION

We are currently considered an “emerging growth company,” within the meaning of the Securities Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “named executive officers,” who are the individuals who served as our principal executive officer and our two other most highly compensated officers who served as executive officers during the last completed fiscal year. In accordance with the foregoing, our named executive officers are:

Name Principal Position

2017 Summary Compensation Table

The following table summarizes, with respect to our named executive officers, information relating to compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2017.

Name and Principal Position	Year		Salary ($)	Bonus ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	Total ($)
		2017
		2017
		2017

Outstanding Equity Awards at 2017 Fiscal Year-End

The following table reflects information regarding outstanding equity-based awards held by our Named Executive Officers as of December 31, 2017.

Name Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options (#) Option
Exercise
Price ($) Option
Expiration
Date Number of
Shares or
Units of
Stock That
Have Not
Vested (#) Market
Value of
Shares or
Units of
Stock That
Have Not
Vested ($) Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested (#) Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested ($)

Long-Term Incentive Plan

In order to incentivize management members, we have adopted the Berry Petroleum Corporation 2017 Omnibus Incentive Plan. Further disclosure regarding this plan will be provided in a future filing.

Director Compensation

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PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth as of             , 2018, information regarding the beneficial ownership of our common stock and Series A Preferred Stock and shows the number of shares of common stock and Series A Preferred Stock and the respective percentages owned by:

• each of the selling stockholders;

• each person known to us beneficially own more than 5% of any class of our outstanding common stock;

• each member of our board of directors;

• each of our named executive officers; and

• all of our directors and executive officers as a group.

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective selling stockholders, 5% or more stockholders, directors or executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o Berry Petroleum Corporation, 5201 Truxtun Ave., Bakersfield, California 93309.

To the extent that the underwriters sell more than             shares of common stock, the underwriters have the option to purchase up to an additional              shares from us. Amounts in the table are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares.

Name of Beneficial Owner(1)	Shares of Common Stock Beneficially Owned Prior to the Offering (1)			Number of Shares of Common Stock Being Offered Hereby	Shares of Common Stock Beneficially Owned After this Offering (Assuming No Exercise of the Underwriters’ Over-Allotment Option)			Shares of Common Stock Beneficially Owned After this Offering (Assuming Full Exercise of the Underwriters’ Over-Allotment Option)
	Number	%			Number	%		Number	%
Directors and named executive officers:
Arthur T. Smith
(President, Chief Executive Officer and Director)			%				%			%
Cary Baetz
(Executive Vice President, Chief Financial Officer and Director)			%				%			%
Gary A. Grove
(Executive Vice President and Chief Operating Officer)			%				%			%
Brent S. Buckley
(Director)			%				%			%
Eugene J. Voiland
(Director)			%				%			%
Kaj Vazales
(Director)			%				%			%
All directors and executive officers as a group (    persons)			%				%			%
Selling stockholders and other 5% stockholders:
			%				%			%

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(1) The amounts and percentages of common stock and Series A Preferred Stock beneficially owned are reported on the bases of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. The number of shares beneficially owned by a person includes stock options, convertible preferred stock, and any other derivative securities to acquire common stock held by that person that are currently exercisable or convertible within 60 days after the date of this prospectus. The shares issuable under any such securities are treated as outstanding for computing the percentage ownership of the person holding these securities, but are not treated as outstanding for the purposes of computing the percentage ownership of any other person.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In connection with our emergence from bankruptcy, we entered into agreements with certain of our affiliates and with parties who received shares of our common stock and Series A Preferred Stock in exchange for their claims. We have filed copies of the agreements referenced in this section as exhibits to the registration statement of which this prospectus is a part.

Registration Rights Agreement

On the Effective Date, Berry Corp. entered into a Registration Rights Agreement with the members of an ad hoc group of holders of the Unsecured Notes (the “Ad Hoc Committee”). For additional information about the Registration Rights Agreement, see “Description of Capital Stock” below.

Stockholders Agreement

On the Effective Date, Berry Corp. and the members of the Ad Hoc Committee entered into a Stockholders Agreement governing the election of directors to the board of directors of Berry Corp. and other governance matters. For additional information about the Stockholders Agreement, see “Description of Capital Stock” below.

Transactions with LINN Energy

Transition Services and Separation Agreement

On the Effective Date, Berry LLC entered into a Transition Services and Separation Agreement (the “TSSA”) with LINN Energy and certain of LINN Energy’s affiliates and subsidiaries to facilitate the separation of our operations from LINN Energy’s operations. Pursuant to the TSSA, (i) LINN Energy was required to provide, or cause to be provided, certain administrative, management, operating, and other services and support (the “Transition Services”) to us for the period from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”), (ii) we and the LINN Energy debtors separated our previously combined enterprise and (iii) the LINN Energy debtors transferred to us certain assets that related to our properties or business, in each case under the terms and conditions specified in the TSSA.

Under the TSSA, we reimbursed LINN Energy for any and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented, in connection with providing the Transition Services. Additionally, we paid to LINN Energy a management fee of $6 million per month, prorated for partial months, during the Transition Period and paid $2.7 million per month, prorated for partial months, from the first day following the Transition Period through the last day of the second full calendar month thereafter (the “Separation Period”). During the Separation Period, the scope of the Transition Services was reduced to specified accounting and administrative functions. The Transition Period under the TSSA ended April 30, 2017, and the Separation Period ended June 30, 2017.

Operating Agreements

On the Effective Date, in connection with the TSSA, Berry LLC and Linn Energy Holdings, LLC, a wholly-owned subsidiary of LINN Energy (“Linn Holdings”), entered into two Operating Agreements governing the joint ownership and operation of certain oil and natural gas assets with respect to which Berry LLC and Linn Holdings, either directly or through an affiliate, would continue to have joint ownership after the Effective Date.

Pursuant to an Operating Agreement (the “Hugoton JOA”), Linn Operating operated the Hugoton assets as agent for Linn Holdings (which owned a working interest in the Hugoton assets).

Pursuant to an Operating Agreement (the “Hill JOA”), Berry LLC operated the Hill assets under the Hill JOA after the Effective Date until we purchased the assets on July 31, 2017.

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Nick Smith Employment Agreement

We currently employ Nick Smith, the son of Arthur T. Smith, our Chief Executive Officer, as Director of Strategic Planning & Commercial Marketing. Consistent with market compensation, Mr. Smith has received $             in aggregate compensation since October 2017.

Procedures for Approval of Related Party Transactions

We intend to adopt a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

• any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

• any person who is known by us to be the beneficial owner of more than 5% of our common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our capital stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our capital stock; and

• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

We anticipate that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.

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DESCRIPTION OF CAPITAL STOCK

Berry Corp.’s authorized capital stock consists of 750,000,000 shares of common stock, par value $0.001 per share, and 250,000,000 shares of preferred stock, par value $0.001 per share. As of February 9, 2018 there were 32,920,000 shares of common stock and 35,845,001 shares of Series A Preferred Stock outstanding. As of February 9, 2018, there was 1 stockholder of record of our common stock.

The following summary of the capital stock and the Certificate of Incorporation and Bylaws of Berry Corp. does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to the Certificate of Incorporation and Bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

Dividends

Subject to the rights granted to any holders of the Series A Preferred Stock, holders of the common stock will be entitled to dividends in the amounts and at the times declared by Berry Corp.’s board of directors in its discretion out of any assets or funds of Berry Corp. legally available for the payment of dividends.

Voting

Each holder of shares of the common stock is entitled to one vote for each share of the common stock on all matters presented to the stockholders of Berry Corp. (including the election of directors). The holders of shares of common stock have no cumulative voting rights. All elections of directors are determined by a plurality of the votes cast, and except as otherwise required by law or by the rules of any stock exchange upon which Berry Corp.’s securities are listed or as otherwise provided in the Bylaws or Certificate of Incorporation, all other matters are determined by a majority of the votes cast affirmatively or negatively, on such matter. Action required or permitted to be taken at an annual or special meeting of stockholders may be taken without a meeting or vote if a written consent setting forth the action is signed by at least the minimum number of votes necessary to authorize or take such action at a meeting.

Liquidation

The holders of the common stock will share equally and ratably in Berry Corp.’s assets on liquidation after payment or provision for all liabilities and any preferential liquidation rights of any preferred stock then outstanding.

Other Rights

The holders of the common stock do not have preemptive rights to purchase shares of Berry Corp.’s stock. The common stock is not convertible, redeemable, assessable or entitled to the benefits of any sinking or repurchase fund. The rights, preferences and privileges of holders of the common stock will be subject to those of the holders of any shares of preferred stock that Berry Corp. may issue in the future.

Under the terms of the Certificate of Incorporation, Berry Corp. is prohibited from issuing any non-voting equity securities to the extent required under Section 1123(a)(6) of the Bankruptcy Code and only for so long as Section 1123 of the Bankruptcy Code is in effect and applicable to Berry Corp.

Limitation of Liability of Directors and Indemnification Matters

The Certificate of Incorporation provides that no director shall be personally liable to Berry Corp. or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any

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breach of the director’s duty of loyalty to Berry Corp. or its stockholders, (ii) for any act or omission not in good faith or which involves intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Delaware General Corporation Law (the “DGCL”), or (iv) for any transaction from which the director derived an improper personal benefit. The effect of this provision is to eliminate Berry Corp.’s and its stockholders’ rights, through stockholders’ derivative suits on Berry Corp’s behalf, to recover monetary damages against a director for a breach of fiduciary duty as a director.

Berry Corp. has entered into indemnification agreements with each of its directors and executive officers. These indemnification agreements require Berry Corp. to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service as a director or executive officer of Berry Corp. In addition, Berry Corp. is also required to advance expenses incurred by such individuals in connection with any proceeding arising by reason of their service. The Certificate of Incorporation also provides that we will indemnify our directors and officers to the fullest extent permitted under Delaware law.

Anti-Takeover Provisions of the Certificate of Incorporation, the Bylaws and the DGCL

The Certificate of Incorporation, the Bylaws and the DGCL contain provisions that may have some anti-takeover effects and may delay, defer or prevent a takeover attempt or a removal of Berry Corp.’s incumbent officers or directors that a stockholder might consider in his, her or its best interest, including those attempts that might result in a premium over the market price for shares held by the stockholders.

Delays in or Prevention of a Change in Control

Provisions in Berry Corp.’s Bylaws could have an effect of delaying, deferring, or preventing a change in control of Berry Corp.

Preferred Stock

The Certificate of Incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.001 per share, covering up to an aggregate of 250,000,000 shares of preferred stock. The board of directors may determine the number of shares in each such series and fix the designation, powers, preferences, rights, qualifications, limitations and restrictions of such series. The number of authorized shares of preferred stock may be increased or decreased by the affirmative vote of the holders of a majority of the voting power of all then-outstanding shares of capital stock of Berry Corp. entitled to vote thereon, without a vote of the holders of the preferred stock, or of any series thereof, unless a vote of any such holders is required pursuant to the terms of any preferred stock designation.

Series A Preferred Stock

In connection with Berry LLC’s emergence from bankruptcy on February 28, 2017, Berry Corp. filed with the Secretary of State of the State of Delaware the Certificate of Designation of Series A Convertible Preferred Stock of Berry Petroleum Corporation (the “Series A Certificate of Designation”). The following is a summary of the material terms of Series A Preferred Stock set forth in the Series A Certificate of Designation.

The Series A Certificate of Designation authorizes the issuance of up to 250,000,000 shares of Series A Preferred Stock. The authorized number of shares of Series A Preferred Stock may be increased or decreased by the board of directors; provided that no decrease shall reduce the number of authorized shares below the number of shares then outstanding plus the number of shares issuable upon exercise or conversion of outstanding rights, options or other securities issued by Berry Corp.

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The Series A Preferred Stock ranks senior to each other series or class of capital stock of Berry Corp. with respect to dividend rights, redemption rights, sale, merger or change of control preference and rights on liquidation, dissolution and winding up of the affairs of Berry Corp.

Holders of Series A Preferred Stock are entitled to receive, when, as and if declared by our board of directors, cumulative dividends at a rate per share of 6.00% per annum of the Series A Accreted Value (as defined in the Series A Certificate of Designation), with such dividends compounding quarterly. On each March 31, June 30, September 30 and December 31 of each year, the amount of any dividends unpaid since the previous regular dividend payment date is added to the liquidation preference by increasing the Series A Accreted Value by any such unpaid dividends in accordance with the terms of the Series A Certificate of Designation. Initially, the Series A Accreted Value was $10.00 per share. Dividends may be paid, at our option, either in cash or in additional shares of Series A Preferred Stock, with such shares of Series A Preferred Stock having a deemed value of $10.00 per share. The Series A Preferred Stock is entitled to vote with holders of common stock, voting together as a single class, with respect to any and all matters subject to a stockholder vote, other than as required by law. Each share of Series A Preferred Stock is entitled to a number of votes equal to the number of shares of common stock into which the share is convertible as of the record date or, if there is no specified record date, as of the date of the vote or written consent, as applicable.

If Berry Corp. liquidates, dissolves or winds up, holders of Series A Preferred Stock, in preference to any other series or class of capital stock of Berry Corp., will be entitled to share ratably in Berry Corp.’s assets that are legally available for distribution to Berry Corp.’s stockholders, after payment of its debts and other liabilities, in an amount per share of Series A Preferred Stock equal to the sum of (i) $10.00 plus (ii) any accrued and unpaid regular dividends.

The Series A Preferred Stock may be converted into a number of shares of common stock determined by the applicable Conversion Rate (as defined in the Series A Certificate of Designation) (i) at the option of the holder at any time and (ii) at our option at any time after February 28, 2021, subject to certain conditions, including that the value of a share of common stock into which a share of Series A Preferred Stock is convertible is equal to or greater than $15.00, based on the volume-weighted average price for any 20-trading day period during the 30 trading days preceding conversion. From the time at which any shares of Series A Preferred Stock are deemed to have been converted, the holder of such converted shares shall no longer be entitled to receive dividends on such Series A Preferred Stock (including any prior accrued or unpaid dividend). The Certificate of Designation contains no financial or operational covenants restricting our activities or our ability to raise capital.

The Series A Preferred Stock is not subject to redemption by Berry Corp. or at the option of any holder of Series A Preferred Stock. The Series A Preferred Stock is not entitled to a retirement or sinking fund.

While shares of Series A Preferred Stock are outstanding, the Certificate of Incorporation must not be amended in any manner that would alter or change the powers, preferences or rights of the Series A Preferred Stock so as to affect holders of the Series A Preferred Stock adversely, without the affirmative vote of holders of a majority of the outstanding shares of Series A Preferred Stock, voting together as a single class.

Amendment of the Bylaws

Under the DGCL, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. The Certificate of Incorporation and the Bylaws grant to the board of directors the power to adopt, amend, restate or repeal the Bylaws, provided that no bylaw adopted by the stockholders may be amended, repealed or readopted by the board of directors if such bylaw so provides. The stockholders may adopt, amend, restate or repeal the Bylaws but only by a vote of holders of a majority in voting power of the outstanding shares of stock entitled to vote thereon, voting together as a single class; provided that any amendment that adversely affects holders of the preferred stock requires the affirmative vote of a majority of the

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preferred stock. Any amendment or waiver of any provision of the Bylaws that adversely affects the rights, preferences or privileges of the holders of the Series A Preferred Stock in any material respect requires the affirmative vote of a majority of the outstanding shares of Series A Preferred Stock outstanding as of the initial issuance.

Other Limitations on Stockholder Actions

• Advance notice is required for stockholders to nominate directors or to submit proposals for consideration at meetings of stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 45 days nor more than 75 days prior to the first anniversary date of the annual meeting for the preceding year. The Bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting

• Until the third annual meeting of stockholders, the affirmative vote of at least 75% of the voting power of the shares entitled to vote generally in the election of directors to remove a director (after such time, directors may be removed with or without cause by the affirmative vote of holders of a majority of the voting power of our shares entitled to vote on the election of directors);

• Stockholders may call a special meeting only upon request of at least 25% of the voting power of the shares entitled to vote in the election of directors.

Forum Selection

The Certificate of Incorporation generally provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

• any derivative action or proceeding brought on our behalf;

• any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee to us or our stockholders;

• any action asserting a claim against us or our directors, officers or employees arising pursuant to any provision of the DGCL, our Certificate of Incorporation or Bylaws; or

• any action asserting a claim against us or our directors, officers or employees that is governed by the internal affairs doctrine.

Although we believe these provisions will benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against our directors, officers, employees and agents. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in the Certificate of Incorporation is inapplicable or unenforceable.

Corporate Opportunity

Under the Certificate of Incorporation, to the extent permitted by law:

• our stockholders are permitted to make investments in competing businesses;

• if a Dual Role Person becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us; and

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• we have renounced our interest in, or in being offered an opportunity to participate in, such corporate opportunities presented to a Dual Role Person.

Newly Created Directorships and Vacancies on the Board of Directors

Under the Bylaws, any vacancies on the board of directors for any reason and any newly created directorships resulting from any increase in the number of directors may be filled (i) by the board of directors upon a vote of a majority of the remaining directors then in office, even if they constitute less than a quorum of the board of directors or by a sole remaining director or (ii) by the stockholders at a special or annual meeting or by written consent by of the majority vote of the holders of a majority of the stockholders voting power of shares entitled to vote on the election of directors at special or annual meeting or by written consent.

Registration Rights

The Registration Rights Agreement requires us to file a shelf registration statement with the SEC as soon as practicable following the Effective Date. The shelf registration statement will register the resale, on a delayed or continuous basis, of all Registrable Securities that have been timely designated for inclusion by the holders (specified in the Registration Rights Agreement). Generally, “Registrable Securities” includes (i) common stock we issued under the Plan, (ii) Series A Preferred Stock that was purchased by the participants in an offering of rights to purchase Series A Preferred Stock under the Plan and (iii) common stock into which the Series A Preferred Stock converts, except that “Registrable Securities” does not include securities that have been sold under an effective registration statement or Rule 144 under the Securities Act or securities that have been transferred to a person other than specified holder or valid transferee.

The Registration Rights Agreement also requires us to effect demand registrations, which the specified holders may request to be underwritten, and underwritten shelf takedowns from the initial shelf registration if requested by holders of a specified percentage of Registrable Securities, subject to customary conditions and restrictions. If Registrable Securities are to be distributed in an underwritten public offering and our common stock is not then listed on a national securities exchange or quoted on a recognized trading market, we must use commercially reasonable efforts to cause the Registrable Securities to be listed on a national securities exchange as promptly as practicable.

If we propose to file a registration statement under the Securities Act or conduct a shelf takedown with respect to a public offering of any class of our equity securities, the specified holders have “piggyback” registration rights to include their Registrable Securities in the registration statement, subject to customary conditions and restrictions.

At any time when we are required to file public reports with the SEC under the Securities Act or the Exchange Act, the Registration Rights Agreement requires us to use commercially reasonable efforts to timely comply with the reporting requirements. If we are not subject to these reporting requirements, we must make available information necessary for the specified holders of Registrable Securities to resell their Registrable Securities in compliance with Section 4(a)(7), Rule 144, Rule 144A and Regulation S, if available, without registration under the Securities Act and within the limitations of the applicable exemptions.

The Registration Rights Agreement will terminate when there are no longer any Registrable Securities outstanding.

Stockholders Agreement

On the Effective Date, we and the members of the Ad Hoc Committee entered into a Stockholders Agreement (the “Stockholders Agreement”) governing the election of directors to our board of directors and other governance matters. Under the Stockholders Agreement, each member of the Ad Hoc Committee (referred

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to in the Stockholders Agreement as the “Stockholder Group”) is required to take all necessary action, including voting in person or by proxy, or executing written consents with respect to, all of our common stock and Series A Preferred Stock that they hold, to cause the following five individuals to be elected as our directors:

• The individual serving as our Chief Executive Officer;

• One individual appointed by Benefit Street Partners (for so long as Benefit Street Partners beneficially owns any common stock or Series A Preferred Stock);

• One individual appointed by Oaktree Capital Management (for so long as Oaktree Capital Management beneficially owns any common stock or Series A Preferred Stock); and

• Two individuals appointed by the Stockholder Group (for so long as the Stockholder Group beneficially owns any common stock or Series A Preferred Stock and by approval of a majority of the common stock and Series A Preferred Stock beneficially owned by all members of the Stockholder Group, voting together).

Under the Stockholders Agreement, no member of the Stockholder Group, nor any of their affiliates, will have any liability as a result of designating or nominating an individual to serve as a director for us, solely for any act or omission by such individual in her or her capacity as a director, or for voting for a director in accordance with the terms of the Stockholders Agreement.

The Stockholders Agreement will terminate automatically upon the occurrence of the third annual meeting of our stockholders. The Stockholders Agreement may be terminated earlier by written agreement between us and the members of the Stockholder Group owning at least a majority of the common stock and Series A Preferred Stock together then beneficially owned by all members of the Stockholder Group; except that any early termination also requires the written agreement of any member of the Stockholder Group that then has a right to appoint a director under the Stockholders Agreement.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock and Series A Preferred Stock is American Stock Transfer & Trust Company, LLC (“AST”). AST’s address is 6201 15th Avenue, Brooklyn, New York 11219, and AST’s phone number is (718) 921-8200.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock, although our common stock has been quoted on the OTC Grey Market under the symbol “BRRP.” Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon completion of this offering, we will have outstanding an aggregate of              shares of common stock. Of these shares, all of the              shares of common stock to be sold in this offering (or              shares assuming the underwriters exercise the option to purchase additional shares in full) will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. Other than as described below with respect to shares issued in reliance on Section 1145 of the Bankruptcy Code, all remaining shares of common stock will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

•              shares of common will be eligible for sale the date of this prospectus;

•              shares will be eligible for sale upon the expiration of the lock-up agreements beginning      days after the date of this prospectus when permitted under Rule 144 or Rule 701.

Lock-up Agreements

We, all of our directors and executive officers and the selling stockholders have agreed not to sell any common stock or securities convertible into or exchangeable for shares of common stock for a period of      days from the date of this prospectus, subject to certain exceptions. Please see “Underwriting” for a description of these lock-up provisions.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled

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to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the              during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register 6,876,500 shares of common stock issuable under our 2017 Incentive Plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

Registration Rights Agreement

As described above in “Certain Relationships and Related Party Transactions—Registration Rights Agreement,” we entered into the Registration Rights Agreement with certain of our stockholders, including the selling stockholders, pursuant to which such stockholders have the right, subject to various conditions and limitations, to demand the filing of a registration statement covering their shares of our common stock and to demand the Company to support underwritten sales of such shares, subject to the limitations specified in the Registration Rights Agreement. By exercising their registration rights and causing a large number of shares to be registered and sold in the public market, these holders could cause the price of our common stock to significantly decline.

Plan of Reorganization

On February 28, 2017, in connection with the emergence of our predecessor company from bankruptcy, we issued 32,920,000 shares of our common stock and 35,845,001 shares of Series A Preferred Stock pursuant to the Plan. 336,586 of the shares of Series A Preferred Stock were issued pursuant to an exemption from registration under Section 4(a)(2) of the Securities Act. The remaining shares of Series A Preferred Stock and all of the common stock were issued pursuant to an exemption from registration under Section 1145(a)(1) of the Bankruptcy Code.

In addition, pursuant to the Plan, the holders of unsecured claims against our predecessor company (other than claims under the Unsecured Notes) (the “Unsecured Claims”) are to receive their pro rata share of either (i) 7,080,000 shares of our common stock or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from a cash distribution pool. As a result, all outstanding obligations arising from the Unsecured Claims were extinguished. To the extent that holders of Unsecured Claims elected to receive cash rather than our common stock in settlement of their allowed claims, the stock they would have received will be

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retained by us as treasury stock. The actual amount of our common stock that that will be issued from the 7,080,000 cannot be known until all claims are settled, adjustments have been made based on the stock to be received by Unsecured Claims and claims under the Unsecured Notes and, the final number of shares of common stock to be received per dollar of Unsecured Claim is known. All such shares currently remain reserved outstanding and to the extent issued, will be also be exempt from registration under Section 1145(a)(1) of the Bankruptcy Code.

Section 1145(a)(1) exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. of our common shares issued pursuant to the Plan may be resold without registration unless the seller is an “underwriter” with respect to those securities. Section 1145(b)(1) defines an “underwriter” as any person who:

• purchases a claim against, an interest in, or a claim for an administrative expense against the debtor, if that purchase is with a view to distributing any security received in exchange for such a claim or interest;

• offers to sell securities offered under the Plan for the holders of those securities;

• offers to buy those securities from the holders of the securities, if the offer to buy is (i) with a view to distributing those securities; and (ii) under an agreement made in connection with the Plan, the competition of the Plan, or with the offer or sale of securities under the Plan;

• or is an “affiliate” of the issuer.

To the extent a person is deemed to be an “underwriter,” resales by such person would not be exempted by Section 1145 from registration under the Securities Act or other applicable law. Those persons would, however, be permitted to sell our shares without registration if they are able to comply with the provisions of Rule 144, as described further above.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

The following is a summary of the material U.S. federal income tax considerations related to the purchase, ownership and disposition of our common stock by a non-U.S. holder (as defined below), that holds our common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service (“IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary does not address all aspects of U.S. federal income taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as:

• banks, insurance companies or other financial institutions;

• tax-exempt or governmental organizations;

• qualified foreign pension funds (or any entities all of the interests of which are held by a qualified foreign pension fund);

• dealers in securities or foreign currencies;

• traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

• persons subject to the alternative minimum tax;

• partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;

• persons deemed to sell our common stock under the constructive sale provisions of the Code;

• persons that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

• certain former citizens or long-term residents of the United States; and

• persons that hold our common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction.

PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

Non-U.S. Holder Defined

For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our common stock that is not for U.S. federal income tax purposes a partnership or any of the following:

• an individual who is a citizen or resident of the United States;

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• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

• an estate the income of which is subject to U.S. federal income tax regardless of its source; or

• a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our common stock by such partnership.

Distributions

Distributions of cash or property on our common stock, if any, will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Common Stock.” Subject to the withholding requirements under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any distribution made to a non-U.S. holder on our common stock generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.

Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

Gain on Disposition of Common Stock

Subject to the discussions below under “—Backup Withholding and Information Reporting” and “—Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized upon the sale or other disposition of our common stock unless:

• the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;

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• the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or

• our common stock constitutes a United States real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes and as a result such gain is treated as effectively connected with a trade or business conducted by the non-U.S. holder in the United States.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation for U.S. federal income tax purposes whose gain is described in the second bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty).

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our common stock continues to be “regularly traded on an established securities market” (within the meaning of the U.S. Treasury Regulations), only a non-U.S. holder that actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the common stock, more than 5% of our common stock will be treated as disposing of a U.S. real property interest and will be taxable on gain realized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock were not considered to be regularly traded on an established securities market, such holder (regardless of the percentage of stock owned) would be treated as disposing of a U.S. real property interest and would be subject to U.S. federal income tax on a taxable disposition of our common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.

Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.

Backup Withholding and Information Reporting

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form).

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United States

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by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements under FATCA

Sections 1471 through 1474 of the Code, and the U.S. Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our common stock and on the gross proceeds from a disposition of our common stock (if such disposition occurs after December 31, 2018), in each case if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners), (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN-E), or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes. Non-U.S. holders are encouraged to consult their own tax advisors regarding the effects of FATCA on an investment in our common stock.

INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.

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UNDERWRITING (CONFLICTS OF INTEREST)

The company and the underwriters named below have entered into an underwriting agreement with respect to the shares being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares indicated in the following table.              is the representative of the underwriters.

Underwriters	Number of Shares
Total

The underwriters are committed to take and pay for all of the shares being offered, if any are taken, other than the shares covered by the option described below unless and until this option is exercised.

The underwriters have an option to buy up to an additional              shares from the company to cover sales by the underwriters of a greater number of shares than the total number set forth in the table above. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above.

The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by the company. Such amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase              additional shares. No underwriting discounts or commissions will be paid by the selling stockholders.

Paid by the Company

	No Exercise	Full Exercise
Per Share	$	$
Total	$	$

Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $             per share from the initial public offering price. After the initial offering of the shares, the representatives may change the offering price and the other selling terms. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The company and its officers, directors, and holders of substantially all of the company’s common stock have agreed with the underwriters, subject to certain exceptions, not to dispose of or hedge any of their common stock or securities convertible into or exchangeable for shares of common stock during the period from the date of this prospectus continuing through the date              days after the date of this prospectus, except with the prior written consent of the representatives. This agreement does not apply to any existing employee benefit plans. See “Shares Eligible for Future Sale” for a discussion of certain transfer restrictions.

Prior to the offering, there has been no public market for the shares, although our common stock has been quoted on the OTC Grey Market under the symbol “BRRP.” The initial public offering price has been negotiated among the company and the representatives. Among the factors to be considered in determining the initial public offering price of the shares, in addition to prevailing market conditions, will be the company’s historical performance, estimates of the business potential and earnings prospects of the company, an assessment of the company’s management and the consideration of the above factors in relation to market valuation of companies in related businesses.

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An application has been made to list the common stock on the              under the symbol “            ”. In order to meet one of the requirements for listing the common stock on the             , the underwriters have undertaken to sell lots of 100 or more shares to a minimum of 400 beneficial holders.

In connection with the offering, the underwriters may purchase and sell shares of common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering, and a short position represents the amount of such sales that have not been covered by subsequent purchases. A “covered short position” is a short position that is not greater than the amount of additional shares for which the underwriters’ option described above may be exercised. The underwriters may cover any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to cover the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase additional shares pursuant to the option described above. “Naked” short sales are any short sales that create a short position greater than the amount of additional shares for which the option described above may be exercised. The underwriters must cover any such naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common stock made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the company’s stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common stock. As a result, the price of the common stock may be higher than the price that otherwise might exist in the open market. The underwriters are not required to engage in these activities and may end any of these activities at any time. These transactions may be effected on             , in the over-the-counter market or otherwise.

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of our common shares may not be made in that Relevant Member State, except that an offer to the public in that Relevant Member State of our common shares may be made at any time under the following exemptions under the Prospectus Directive:

(a)    to any legal entity which is a qualified investor as defined in the Prospectus Directive;

(b)    to fewer than 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive), subject to obtaining the prior consent of              for any such offer; or

(c)    in any other circumstances falling within Article 3(2) of the Prospectus Directive, provided that no such offer of shares of our common stock shall result in a requirement for the publication by us or any underwriter of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer to the public” in relation to our common shares in any Relevant Member State means the communication in any form and by any means of sufficient information

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on the terms of the offer and our common shares to be offered so as to enable an investor to decide to purchase our common shares, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State, the expression “Prospectus Directive” means Directive 2003/71/EC (as amended), including by Directive 2010/73/EU, and includes any relevant implementing measure in the Relevant Member State.

This European Economic Area selling restriction is in addition to any other selling restrictions set out below.

United Kingdom

In the United Kingdom, this prospectus is only addressed to and directed as qualified investors who are (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the Order); or (ii) high net worth entities and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). Any investment or investment activity to which this prospectus relates is available only to relevant persons and will only be engaged with relevant persons. Any person who is not a relevant person should not act or relay on this prospectus or any of its contents.

Canada

The securities may be sold in Canada only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions, and Ongoing Registrant Obligations. Any resale of the securities must be made in accordance with an exemption form, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

Hong Kong

The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies (Winding Up and Miscellaneous Provisions) Ordinance (Cap. 32 of the Laws of Hong Kong) (“Companies (Winding Up and Miscellaneous Provisions) Ordinance”) or which do not constitute an invitation to the public within the meaning of the Securities and Futures Ordinance (Cap. 571 of the Laws of Hong Kong) (“Securities and Futures Ordinance”), or (ii) to “professional investors” as defined in the Securities and Futures Ordinance and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies (Winding Up and Miscellaneous Provisions) Ordinance, and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities

154

laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” in Hong Kong as defined in the Securities and Futures Ordinance and any rules made thereunder.

Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor (as defined under Section 4A of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”)) under Section 274 of the SFA, (ii) to a relevant person (as defined in Section 275(2) of the SFA) pursuant to Section 275(1) of the SFA, or any person pursuant to Section 275(1A) of the SFA, and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor, the securities (as defined in Section 239(1) of the SFA) of that corporation shall not be transferable for 6 months after that corporation has acquired the shares under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer in that corporation’s securities pursuant to Section 275(1A) of the SFA, (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32 of the Securities and Futures (Offers of Investments) (Shares and Debentures) Regulations 2005 of Singapore (“Regulation 32”)    Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole purpose is to hold investments and each beneficiary of the trust is an accredited investor, the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable for 6 months after that trust has acquired the shares under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer that is made on terms that such rights or interest are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction (whether such amount is to be paid for in cash or by exchange of securities or other assets), (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32.

Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Act of Japan (Act No. 25 of 1948, as amended), or the FIEA. The securities may not be offered or sold, directly or indirectly, in Japan or to or for the benefit of any resident of Japan (including any person resident in Japan or any corporation or other entity organized under the laws of Japan) or to others for reoffering or resale, directly or indirectly, in Japan or to or for the benefit of any resident of Japan, except pursuant to an exemption from the registration requirements of the FIEA and otherwise in compliance with any relevant laws and regulations of Japan.

The company estimates that their share of the total expenses of the offering, excluding underwriting discounts and commissions, will be approximately $            .

155

The company has agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act of 1933.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to the issuer and to persons and entities with relationships with the issuer, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of the issuer (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships with the issuer. The underwriters and their respective affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

156

LEGAL MATTERS

The validity of the notes offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by             .

EXPERTS

The financial statements of Berry Petroleum Company, LLC (Debtor-in-Possession) (the “Company”) as of December 31, 2016 and 2015, and for each of the years in the two-year period ended December 31, 2016, have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, and upon the authority of said firm as experts in auditing and accounting.

The audit report covering the December 31, 2016 financial statements contains an explanatory paragraph that states that the United States Bankruptcy Court for the Southern District of Texas confirmed the Company’s Plan of Reorganization (the “Plan”) on January 27, 2017. Confirmation of the Plan resulted in the discharge of debt of the Company and substantially altered rights and interests of debt and equity security holders as provided for in the Plan. The Plan was substantially consummated on February 28, 2017 and the Company emerged from bankruptcy as a wholly-owned subsidiary of Berry Petroleum Corporation in accordance with the Plan. In connection with its emergence from bankruptcy, the Company adopted fresh-start accounting as of February 28, 2017.

Certain estimates of our oil and natural gas reserves and related information included in this prospectus have been derived from reports prepared by the independent engineering firm, DeGolyer and MacNaughton. All such information has been so included on the authority of such firms as experts regarding the matters contained in their reports.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

As a result of the offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

157

INDEX TO FINANCIAL STATEMENTS

Historical Financial Statements
Condensed Consolidated Financial Statements for the Seven Months Ended September 30, 2017, the Two Months Ended February 28, 2017 and the Nine Months Ended September 30, 2016 (Unaudited)
Condensed Consolidated Balance Sheets as of September  30, 2017 and December 31, 2016	F-2
Condensed Consolidated Statements of Operations for the Seven Months Ended September 30, 2017, the Two Months Ended February 28, 2017 and the Nine Months Ended September 30, 2016	F-3
Condensed Consolidated Statements of Cash Flows for the Seven Months Ended September 30, 2017, the Two Months Ended February 28, 2017 and the Nine Months Ended September 30, 2016	F-4
Condensed Consolidated Statements of Equity as of December  31, 2016, September 30, 2017 and 2016, and as of February 28, 2017	F-5
Notes to the Condensed Consolidated Financial Statements	F-6
Consolidated Financial Statements for the Years Ended December 31, 2016 and 2015
Report of Independent Auditors	F-33
Consolidated Balance Sheets as of December 31, 2016 and 2015	F-34
Consolidated Statements of Operations for the Years Ended December  31, 2016 and 2015	F-35
Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 2016 and 2015	F-36
Consolidated Statements of Cash Flows for the Years Ended December  31, 2016 and 2015	F-37
Notes to the Consolidated Financial Statements	F-38

F-1

BERRY PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	Berry Corp. (Successor)			Berry LLC (Predecessor)
	September 30, 2017			December 31, 2016
	(unaudited)
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	2,926		$	30,483
Accounts receivable, net		51,453			51,175
Derivative instruments		971			—
Restricted cash		35,000			128
Other current assets		20,955			16,218
Total current assets		111,305			98,004
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		1,324,683			5,026,810
Less accumulated depletion and amortization		(37,512	)		(2,789,368	)
		1,287,171			2,237,442
Other property and equipment		103,711			123,460
Less accumulated depreciation		(4,896	)		(20,759	)
		98,815			102,701
Derivative instruments		4,010			—
Restricted cash		—			197,793
Other noncurrent assets		78,088			16,110
Total noncurrent assets		1,468,084			2,554,046
Total assets	$	1,579,389		$	2,652,050
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	109,003		$	65,858
Derivative instruments		6,826			8,896
Current portion of long-term debt		—			891,259
Liabilities subject to compromise		35,000			—
Other accrued liabilities		—			3,140
Total current liabilities		150,829			969,153
Noncurrent liabilities:
Derivative instruments		7,729			10,221
Long-term debt		379,000			—
Other noncurrent liabilities		61,858			169,160
Liabilities subject to compromise		—			1,000,553
Deferred income taxes		8,823			—
Asset retirement obligation		93,609			—
Total noncurrent liabilities		551,019			1,179,934
Commitments and Contingencies-Note 7
Stockholders’/member’s equity:
Successor Series A convertible preferred stock ($.001 par value, 250,000,000 shares authorized and 35,845,001 shares issued at September 30, 2017; no shares authorized and issued at December 31, 2016)		335,000			—
Successor common stock ($.001 par value, 750,000,000 shares authorized and 32,920,000 shares issued at September 30, 2017; no shares authorized or issued at December 31, 2016)		33			—
Predecessor additional paid-in-capital		—			2,798,713
Successor additional paid-in-capital		528,696			—
Predecessor accumulated deficit		—			(2,295,750	)
Retained earnings		13,812			—
Total Stockholders’/member’s equity		877,541			502,963
Total liabilities and equity	$	1,579,389		$	2,652,050

The accompanying notes are an integral part of these financial statements.

F-2

BERRY PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Berry Corp. (Successor)			Berry LLC (Predecessor)
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016
	(Unaudited)			(Unaudited)
				(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	237,324		$	74,120		$	285,538
Electricity sales		15,517			3,655			17,573
(Losses) gains on oil and natural gas derivatives		5,642			12,886			1,642
Marketing revenues		1,901			633			2,743
Other revenues		3,902			1,424			5,634
		264,286			92,718			313,130
Expenses:
Lease operating expenses		108,751			28,238			138,557
Electricity generation expenses		10,192			3,197			12,118
Transportation expenses		18,645			6,194			32,518
Marketing expenses		1,674			653			2,173
General and administrative expenses		39,791			7,964			65,313
Depreciation, depletion and amortization		48,392			28,149			139,980
Impairment of long-lived assets		—			—			1,030,588
Taxes, other than income taxes		25,113			5,212			20,614
(Gains) losses on sale of assets and other, net		(20,687	)		(183	)		(137	)
		231,871			79,424			1,441,724
Other income and (expenses):
Interest expense		(12,482	)		(8,245	)		(48,719	)
Other, net		4,070			(63	)		(79	)
		(8,412	)		(8,308	)		(48,798	)
Reorganization items, net		(1,001	)		(507,720	)		(38,829	)
(Loss) income before income taxes		23,002			(502,734	)		(1,216,221	)
Income tax (benefit) expense		9,190			230			196
Net (loss) income		13,812		$	(502,964	)	$	(1,216,417	)
Undeclared dividends on Series A preferred stock		(12,681	)		n/a			n/a
Net income available to common stockholders	$	1,131			n/a			n/a
Earnings per share attributable to common stock:
Basic	$	0.03			n/a			n/a
Diluted	$	0.03			n/a			n/a

The accompanying notes are an integral part of these financial statements.

F-3

BERRY PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Berry LLC (Successor)			Berry Corp. (Predecessor)
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016
	(Unaudited)			(Unaudited)
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	13,812		$	(502,964	)	$	(1,216,417	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		48,392			28,149			139,980
Amortization of debt issuance costs		857			416			1,226
Impairment of long-lived asset		—			—			1,030,588
Stock-based compensation expense		902			—			—
Deferred income taxes		8,823			9			71
Gain on sale of assets and other, net		(20,687	)		(25	)		(874	)
Reorganization expenses, net		—			501,872			22,866
Derivatives activities:
Total (gains) losses		(5,642	)		(12,886	)		2,963
Cash settlements		9,902			534			8,007
Cash settlements on canceled derivatives		—			—			1,701
Changes in assets and liabilities:
Increase in accounts receivable, net		(2,125	)		(9,152	)		(2,839	)
Decrease (increase) in other assets		(12,130	)		(2,842	)		(3,175	)
Decrease (increase) in restricted cash		17,860			(52,732	)		—
Increase (decrease) in accounts payable and accrued expenses		12,083			18,455			17,866
Increase in other liabilities		16,317			990			1,306
Net cash provided by (used in) operating activities		88,364			(30,176	)		3,269
Cash flow from investing activities:
Capital expenditures:
Development of oil and natural gas properties		(41,075	)		(859	)		(16,168	)
Purchases of other property and equipment		(11,497	)		(2,299	)		(10,366	)
Decrease in restricted cash		—			—			53,418
Purchase of properties and equipment and other		(256,814	)		—			—
Proceeds from sale of properties and equipment and other		234,823			25			172
Net cash (used in) provided by investing activities		(74,563	)		(3,133	)		27,056
Cash flow from financing activities:
Proceeds from sale of Series A convertible preferred stock		—			335,000			—
Borrowings under new credit facility		390,800			—			—
Repayments on new credit facility		(11,800	)		—			—
Repayments on previous credit facility		(451,000	)		(300,000	)		(1,701	)
Borrowings under previous credit facility		51,000			—			—
Debt issuance costs		(22,049	)		—			—
Net cash (used in) provided by financing activities		(43,049	)		35,000			(1,701	)
Net (decrease) increase in cash and cash equivalents		(29,248	)		1,691			28,624
Cash and cash equivalents:
Beginning		32,174			30,483			1,023
Ending	$	2,926		$	32,174		$	29,647

The accompanying notes are an integral part of these financial statements.

F-4

BERRY PETROLEUM COMPANY, LLC

(PREDECESSOR)

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Series A Convertible Preferred Stock				Common stock				Additional Paid-in Capital			Accumulated (Deficit)			Total Member’s equity
	Shares		Amount		Shares		Amount
	(in thousands)
Balance, December 31, 2015 (Predecessor)		—		—		—		—	$	2,798,713		$	(1,012,554	)	$	1,786,159
Net loss		—		—		—		—		—			(1,216,417	)		(1,216,417	)
Balance, September 30, 2016 (Predecessor)		—		—		—		—		2,798,713			(2,228,971	)		569,742
Balance, February 28, 2017 (Predecessor)		—		—		—		—		2,798,714			(2,798,714	)		—
Cancellation of Predecessor Equity		—		—		—		—		(2,798,714	)		2,798,714			—
Balance, February 28, 2017 (Predecessor)		—	$	—		—	$	—	$	—		$	—		$	—

BERRY PETROLEUM CORPORATION

(SUCCESSOR)

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Series A Convertible Preferred Stock				Common stock				Additional Paid-in Capital			Retained Earnings			Total Stockholders’ equity
Issuance of Series A convertible preferred stock		35,845	$	335,000		—	$	—	$	—		$	—		$	335,000
Issuance of Common Stock		—		—		32,920		33		527,794			—			527,827
Beneficial conversion feature related to Series A convertible preferred stock		—		—		—		—		27,750			(27,750	)		—
Elimination of accumulated deficit		—		—		—		—		(27,750	)		27,750			—
Balance, February 28, 2017 (Successor)		35,845		335,000		32,920		33		527,794			—			862,827
Net income		—		—		—		—		—			13,812			13,812
Stock based compensation		—		—		—		—		902			—			902
Balance, September 30, 2017 (Successor)		35,845	$	335,000		32,920	$	33	$	528,696		$	13,812		$	877,541

The accompanying notes are an integral part of these financial statements.

F-5

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

September 30, 2017

Note 1 – Basis of Presentation

“Berry Corp.” refers to Berry Petroleum Corporation, a Delaware corporation that is the sole member of Berry LLC.

“Berry LLC” refers to Berry Petroleum Company, LLC, a Delaware limited liability company that is wholly owned by Berry Corp.

As the context may require, the “Company”, “we”, “our” or similar words refer to (i) Berry Corp. (“the Successor”) and Berry LLC, its consolidated subsidiary, as a whole or (ii) either Berry Corp. or Berry LLC on an individual basis. References to historical activities of the “Company” prior to February 28, 2017, refer to activities of Berry LLC (“the Predecessor”).

“LINN Energy” refers to Linn Energy, LLC, a Delaware limited liability company of which Berry LLC was formerly a wholly-owned, indirect subsidiary.

Subsequent events have been evaluated through February 9, 2018, the date these financial statements were available to be issued. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the financial statements and related footnotes.

Nature of Business

Berry Corp. is an independent oil and natural gas company that was incorporated under Delaware law on February 13, 2017. Berry Corp. operates through its wholly-owned subsidiary, Berry LLC.

On December 16, 2013, an affiliate of LINN Energy, LinnCo, LLC (“LinnCo”), acquired all the outstanding common shares of Berry Petroleum Company and contributed Berry Petroleum Company to LINN Energy in exchange for LINN Energy units. In connection with its acquisition by LINN Energy, Berry Petroleum Company was converted from a Delaware corporation into a Delaware limited liability company and changed its name to “Berry Petroleum Company, LLC.” Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, became Berry LLC’s sole member.

As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), the LINN entities and, consequently, Berry LLC (collectively, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 (“Chapter 11”) of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040 (collectively, the “Chapter 11 Proceedings”). During the pendency of the Chapter 11 Proceedings, the debtors in the Chapter 11 Proceedings (the “Debtors”), operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy as a stand-alone company separate from LINN Energy effective February 28, 2017 (the “Effective Date”).

Our properties are located in the United States (“U.S.”), in California (in the San Joaquin and Ventura basins), Utah (in the Uinta basin), Colorado (in the Piceance basin) and east Texas.

F-6

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Principles of Consolidation and Reporting

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiary. All significant intercompany transactions and balances have been eliminated upon consolidation.

Bankruptcy Accounting

The condensed consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of GAAP. GAAP requires that the financial statements, for periods subsequent to filing of the Chapter 11 Proceeding, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on our condensed consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on our condensed balance sheet. These liabilities are reported at the amounts allowed as claims by the Bankruptcy Court, although they may be settled for less.

Upon emergence from bankruptcy on February 28, 2017, we adopted fresh-start accounting which resulted in Berry Corp. becoming the financial reporting entity. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the condensed consolidated financial statements on or after February 28, 2017 are not comparable to the condensed consolidated financial statements prior to that date. See Note 3 for additional information.

Use of Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make informed estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. In addition, as part of fresh-start accounting, we made estimates and assumptions related to our reorganization value, liabilities subject to compromise and the fair value of assets and liabilities recorded.

As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

F-7

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Recently Issued Accounting Standards

In May 2017, the Financial Accounting Standards Board (“FASB”) issued rules to simplify the guidance on the modification of share-based payment awards. The amendments provide clarity on which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting prospectively. The rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

In January 2017, the FASB issued rules that changed the definition of a business to assist entities with evaluating when a set of transferred assets and activities is a business. The rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

In November 2016, the FASB issued rules intended to address the diversity in practice in the classification and presentation of changes in restricted cash on the statement of cash flows. These rules will be applied retrospectively as of the date of adoption and are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). We are currently evaluating the impact of the adoption of these rules on our financial statements and related disclosures. This is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and require additional disclosures.

In August 2016, the FASB issued rules that modify how certain cash receipts and cash payments are presented and classified in the statement of cash flows. These rules are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with earlier adoption permitted. We are currently evaluating the impact of these rules on our financial statements.

In June 2016, the FASB issued rules that change how entities will measure credit losses for certain financial assets and other instruments that are not measured at fair value. These rules are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of these rules on our financial statements.

In February 2016, the FASB issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. These rules will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with earlier application permitted. We are currently evaluating the impact of these rules on our financial statements.

In January 2016, the FASB issued rules that modify how entities measure equity investments and present changes in the fair value of financial liabilities. Unless the investments qualify for a practicality exception, the new rules require all equity investments to be measured at fair value with changes in the fair value recognized through net income (other than those accounted for under the equity method of accounting or those that result in consolidation of the investee). Entities will have to record changes in instrument-specific credit risk for financial liabilities measured under the fair value option in other comprehensive income. These new rules become effective for fiscal years beginning after December 15, 2017 with no early adoption permitted. We do not expect the adoption of these rules to have a significant impact on our financial statements.

F-8

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

During 2016, the FASB issued rules clarifying the new revenue recognition standard issued in 2014. The new rules are intended to improve and converge the financial reporting requirements for revenue from contracts with customers. For non-public companies, these rules are effective for fiscal years beginning after December 15, 2018, including interim periods within those years. We are currently evaluating the impact of the adoption of these rules on our financial statements and related disclosures.

Note 2 – Emergence from Voluntary Reorganization under Chapter 11

On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.

In December 2016, Berry LLC and Linn Acquisition Company, LLC, on the one hand, and LINN Energy and its other affiliated debtors, on the other hand, filed separate plans of reorganization with the Bankruptcy Court. The “Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC” (the “Plan”) was filed on December 13, 2016. On January 27, 2017, the Bankruptcy Court entered its confirmation order (the “Confirmation Order”) approving and confirming the Plan.

On February 28, 2017, the Plan became effective and was implemented in accordance with its terms. Among other transactions, Linn Acquisition Company, LLC transferred 100% of Berry LLC’s outstanding membership interests to Berry Corp. As a result, Berry LLC emerged from bankruptcy as a wholly-owned subsidiary of Berry Corp., separate from LINN Energy and its affiliates.

Plan of Reorganization

On the Effective Date, the Company consummated the following reorganization transactions in accordance with the Plan:

• Linn Acquisition Company, LLC transferred 100% of the outstanding membership interests in Berry LLC to Berry Corp. pursuant to an Assignment Agreement. Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.

• The holders of claims under the Company’s Second Amended and Restated Credit Agreement, dated November 15, 2010, by and among Berry LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and certain lenders, (as amended, the “Pre-Emergence Credit Facility”), received (i) their pro rata share of a cash paydown and (ii) pro rata participation in the new facility (the “Emergence Credit Facility”). As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.

• Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A, as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments. For additional information about the Emergence Credit Facility, see Note 5.

• The holders of the Company’s 6.75% senior notes due 2020, issued by Berry LLC pursuant to a Second Supplemental Indenture, dated November 1, 2010, and 6.375% senior notes due 2022, issued by Berry LLC pursuant to a Third Supplemental Indenture, dated March 9, 2012 (collectively, the “Unsecured Notes”), received a right to their pro rata share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Cash

F-9

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Distribution Pool”) and (ii) specified rights to participate in a two-tranche offering of rights to purchase Series A Preferred Stock at an aggregate purchase price of $335 million (as further defined in the Plan, the “Berry Rights Offerings”). As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.

• The holders of unsecured claims against the Company (other than the Unsecured Notes) (the “Unsecured Claims”) received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. As a result, all outstanding obligations under the Unsecured Notes and the indentures governing such obligations were canceled and the obligations arising from the Unsecured Claims were extinguished.

• Berry LLC settled all intercompany claims against the LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy which Berry LLC has fully-reserved.

Liabilities Subject to Compromise

Berry LLC’s condensed balance sheet as of December 31, 2016, included amounts classified as “liabilities subject to compromise,” which represented prepetition liabilities that were allowed, or that the Company estimated would be allowed, as claims in its Chapter 11 case. The following table summarizes the components of liabilities subject to compromise included on the condensed balance sheet:

	Berry LLC (Predecessor)
	December 31, 2016
	(in thousands)
Accounts payable and accrued expenses	$	151,515
Accrued interest payable		15,238
Debt		833,800
Liabilities subject to compromise	$	1,000,553

Through the claims resolution process, many claims were disallowed by the Bankruptcy Court because they were duplicative, amended or superseded by later filed claims, were without merit, or were otherwise overstated. Throughout the Chapter 11 proceedings, the Debtors also resolved many claims through settlements or by Bankruptcy Court orders following the filing of an objection. The Debtors will continue to settle claims and file additional objections with the Bankruptcy Court. To the extent that such adjustments relate to Unsecured Claims, no additional liability to the Company is anticipated as such claimants are only entitled to a pro rata share of 7,080,000 shares of common stock in the Company or, for unaccredited investors who irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. The liability for this cash distribution pool is included in liabilities subject to compromise. In light of the substantial number and amounts of claims filed, we expect the claims resolution process and the ultimate number and amount of, or exact recovery with respect to, allowed Unsecured claims, will take considerable time to complete.

F-10

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Reorganization Items, Net

We have incurred and continue to incur expenses associated with the reorganization. Reorganization items, net represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined. The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations:

	Successor			Predecessor
	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017			Nine Months Ended September 30, 2016
	(in thousands)
Gain on settlement of liabilities subject to compromise	$	—		$	437,474		$	—
Unamortized premiums		—			—			10,923
Terminated contracts		—			—			(34,725	)
Fresh-start valuation adjustments		—			(920,699	)		—
Legal and other professional advisory fees		(1,001	)		(19,481	)		(15,949	)
Other		—			(5,014	)		922
Reorganization items, net	$	(1,001	)	$	(507,720	)	$	(38,829	)

Note 3 – Fresh-Start Accounting

Upon our emergence from Chapter 11 bankruptcy, we adopted fresh-start accounting which resulted in our becoming a new entity for financial reporting purposes. We were required to adopt fresh-start accounting upon our emergence from Chapter 11 because (i) the holders of existing voting ownership interests of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of our assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims, as shown below:

	(in thousands)
Liabilities subject to compromise	$	1,000,336
Pre-petition debt not classified as subject to compromise		891,259
Post-petition liabilities		245,701
Total post-petition liabilities and allowed claims		2,137,296
Reorganization value of assets immediately prior to implementation of the Plan		(1,706,885	)
Excess post-petition liabilities and allowed claims	$	430,411

Upon adoption of fresh-start accounting, the reorganization value derived from the enterprise value was allocated to our assets and liabilities based on their fair values in accordance with GAAP. The Effective Date fair values of our assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The effects of the Plan and the application of fresh-start accounting were reflected in the financial statements as of February 28, 2017, and the related adjustments thereto were recorded on the statement of operations for the two months ended February 28, 2017.

F-11

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

As a result of the adoption of fresh-start accounting and the effects of the implementation of the Plan, our condensed consolidated financial statements subsequent to February 28, 2017, are not comparable to our condensed consolidated financial statements prior to February 28, 2017.

Our condensed consolidated financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to February 28, 2017. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

Reorganization Value

Under GAAP, a value was assigned to the equity of the emerging entity as of the date of adoption of fresh-start accounting. The Plan and disclosure statement approved by the Bankruptcy Court did not include an enterprise value or reorganization value, nor did the Bankruptcy Court approve a value as part of its confirmation of our Plan. Our reorganization value was derived from an estimate of enterprise value, or the fair value of our long-term debt, stockholders’ equity and working capital. Reorganization value approximates the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring. Based on the various estimates and assumptions necessary for fresh-start accounting, our enterprise value as of the Effective Date was estimated to be approximately $1.3 billion. The enterprise value was estimated using a sum of parts approach. The sum of parts approach represents the summation of the indicated fair value of the component assets of the Company. The fair value of our assets was estimated by relying on a combination of the income, market and cost approaches.

The estimated enterprise value, reorganization value and equity value are highly dependent on the achievement of the financial results contemplated in our underlying projections. While we believe the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. Additionally, the assumptions used in estimating these values are inherently uncertain and require judgment. The primary assumptions for which there is a reasonable possibility of the occurrence of a variation that would have significantly affected the reorganization value include those regarding pricing, discount rates and the amount and timing of capital expenditures.

Our principal assets are our oil and natural gas properties. The fair values of oil and natural gas properties were estimated using a valuation technique consistent with the income approach; specifically the discounted cash flows method. We also used the market approach to corroborate the valuation results from the income approach. We used a market-based weighted average cost of capital discount rate of 10% for proved and unproved reserves, with further risk adjustment factors applied to the discounted values. The underlying commodity prices embedded in our estimated cash flows are based on the New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that we believe will impact realizable prices. NYMEX forward curve pricing was used for years 2017 through 2019 and then was escalated at approximately 2.0%.

F-12

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

See below under “Fresh-Start Adjustments” for additional information regarding assumptions used in the valuation of our various other significant assets and liabilities.

The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date:

	(in thousands)
Enterprise value	$	1,262,827
Plus: Fair value of non-debt liabilities		298,211
Reorganization value of the Successor’s assets	$	1,561,038

The fair value of non-debt liabilities consists of liabilities assumed by the Successor on the Effective Date and excludes the fair value of long-term debt.

Condensed Consolidated Balance Sheet

The adjustments included in the following fresh-start condensed consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and executed on the Effective Date (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, methods used to determine the fair values and significant assumptions.

	As of February 28, 2017
	Predecessor			Reorganization Adjustments (1)			Fresh-Start Adjustments			Successor
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	27,407		$	4,642	(2)	$	—		$	32,049
Accounts receivable – trade, net		60,327			—			(816	)(13)		59,511
Derivative instruments		243			—			—			243
Restricted cash		128			52,732	(3)		—			52,860
Other current assets		18,437			(5,558	)(4)		3,873	(14)		16,752
Total current assets		106,542			51,816			3,057			161,415
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		5,031,498			—			(3,787,898	)(15)		1,243,600
Less accumulated depletion and amortization		(2,814,999	)		—			2,814,999	(15)		—
		2,216,499			—			(972,899	)		1,243,600
Other property and equipment		124,379			—			(15,576	)(16)		108,803
Less accumulated depreciation		(22,107	)		—			22,107	(16)		—
		102,272			—			6,531			108,803
Derivative instruments		57			—			—			57
Restricted cash		197,939			(197,814	)(2)		—			125
Other noncurrent assets		16,076			151	(5)		30,811	(17)		47,038
		214,072			(197,663	)		30,811			47,220
Total noncurrent assets		2,532,843			(197,663	)		(935,557	)		1,399,623
Total assets	$	2,639,385		$	(145,847	)	$	(932,500	)	$	1,561,038

F-13

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

	As of February 28, 2017
	Predecessor			Reorganization Adjustments (1)			Fresh Start Adjustments			Successor
	(in thousands)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	60,323		$	68,071	(6)	$	3,818	(18)	$	132,212
Derivative instruments		5,355			—			—			5,355
Current portion of long-term debt, net		891,259			(891,259	)(7)		—			—
Other accrued liabilities		7,334			(3,760	)(8)		1,296	(19)		4,870
Total current liabilities		964,271			(826,948	)		5,114			142,437
Derivative instruments		1,710			—			—			1,710
Long-term debt		—			400,000	(9)		—			400,000
Other noncurrent liabilities		170,979			—			(16,915	)(20)		154,064
Liabilities subject to compromise		1,000,336			(1,000,336	)(10)		—			—
Member’s/stockholders’ equity:
Predecessor additional paid-in capital		2,798,714			(2,798,714	)(11)		—			—
Predecessor accumulated deficit		(2,296,625	)		390,860	(12)		1,905,765	(21)		—
Successor preferred stock		—			335,000	(11)		—			335,000
Successor common stock		—			33	(11)		—			33
Successor additional paid-in capital		—			3,354,258	(11)		(2,826,464	)(21)		527,794
Total member’s/stockholders’ equity		502,089			1,281,437			(920,699	)		862,827
Total liabilities and equity	$	2,639,385		$	(145,847	)	$	(932,500	)	$	1,561,038

Reorganization Adjustments:

(1) Represent amounts recorded as of the Effective Date for the implementation of the Plan, including, among other items, settlement of the Predecessor’s liabilities subject to compromise, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s common stock and preferred stock, proceeds received from the Berry Rights Offerings and issuance of the Successor’s debt.

F-14

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

(2) Changes in cash and cash equivalents included the following:

	(in thousands)
Borrowings under the Emergence Credit Facility	$	400,000
Proceeds from issuance of preferred stock pursuant the Berry Rights Offerings		335,000
Cash receipt from Linn Energy, LLC for ad valorem taxes		23,366
Removal of restriction on cash balance (includes $128 previously recorded as short term)		197,942
Payment to the holders of claims under the Pre-Emergence Credit Facility (including $29 in bank fees and $3,760 in interest)		(897,663	)
Payment of professional fees		(992	)
Payment of Emergence Credit Facility fee that was capitalized		(151	)
Funding of the general unsecured claims Cash Distribution Pool		(35,000	)
Funding of the professional fees escrow account		(17,860	)
Changes in cash and cash equivalents	$	4,642

(3) Primarily reflects the transfer to restricted cash to fund the Predecessor’s professional fees escrow account and general unsecured claims Cash Distribution Pool.

(4) Primarily reflects the write-off of the Predecessor’s deferred financing fees.

(5) Reflects the capitalization of deferred financing fees related to the Emergence Credit Facility.

(6) Net increase in accounts payable and accrued expenses reflects:

	(in thousands)
Recognition of payables for the general unsecured claims Cash Distribution Pool	$	35,000
Recognition of payables for the professional fees escrow account		17,860
Recognition of payable for ad valorem tax liability		23,366
Net change of other professional fees payable		(8,161	)
Other		6
Net increase in accounts payable and accrued expenses	$	68,071

(7) Reflects the repayment of the Pre-Emergence Credit Facility.

(8) Reflects the payment of accrued interest on the Pre-Emergence Credit Facility.

(9) Reflects borrowings under the Emergence Credit Facility.

F-15

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

(10) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows:

	(in thousands)
Accounts payable and accrued expenses	$	151,298
Accrued interest payable		15,238
Debt		833,800
Total liabilities subject to compromise		1,000,336
Funding of the general unsecured claims Cash Distribution Pool		(35,000	)
Common stock to holders of Unsecured Notes and general unsecured creditors		(527,862	)
Gain on settlement of liabilities subject to compromise	$	437,474

(11) Net increase in capital accounts reflects:

	(in thousands)
Common stock to holders of Unsecured Notes and general unsecured creditors	$	527,862
Payment of issuance costs		(35	)
Dividend related to beneficial conversion feature of preferred stock		27,750
Cancellation of the Predecessor’s additional paid-in capital		2,798,714
Par value of common stock		(33	)
Change in additional paid-in capital		3,354,258
Proceeds from issuance of preferred stock		335,000
Par value of common stock		33
Predecessor’s additional paid-in capital		(2,798,714	)
Net increase in capital accounts	$	890,577

See Note 8 for additional information on the issuances and distributions of the Successor’s common and preferred stock.

(12) Net decrease in accumulated deficit reflects:

	(in thousands)
Recognition of gain on settlement of liabilities subject to compromise	$	437,474
Recognition of professional fees		(13,667	)
Write-off of deferred financing fees		(5,197	)
Total reorganization items, net		418,610
Dividend related to beneficial conversion feature of preferred stock		(27,750	)
Net decrease in accumulated deficit	$	390,860

F-16

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Fresh-Start Adjustments:

(13) Reflects a change in accounting policy from the entitlements method to the sales method for natural gas production imbalances.

(14) Primarily reflects an increase in the current portion of greenhouse gas allowances.

(15) Reflects a decrease of oil and natural gas properties, based on the methodology discussed in Note 4, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date:

	Successor		Predecessor
	Fair Value		Historical Book Value
	(in thousands)
Proved properties	$	712,400	$	4,266,843
Unproved properties		531,200		764,655
		1,243,600		5,031,498
Less accumulated depletion and amortization		—		(2,814,999	)
	$	1,243,600	$	2,216,499

(16) Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Effective Date:

	Successor		Predecessor
	Fair Value		Historical Book Value
	(in thousands)
Natural gas plants and pipelines	$	91,427	$	109,675
Land		8,262		201
Furniture and office equipment		5,040		3,879
Buildings and leasehold improvements		2,740		5,884
Vehicles		1,156		4,542
Drilling and other equipment		178		198
		108,803		124,379
Less accumulated depreciation		—		(22,107	)
	$	108,803	$	102,272

In estimating the fair value of other property and equipment, we used a combination of cost and market approaches. A cost approach was used to value our natural gas plants and pipelines, buildings, and furniture and office equipment based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets. A market approach was used to value our vehicles, drilling and other equipment, and land, using recent transactions of similar assets to determine the fair value from a market participant perspective.

(17) Primarily reflects an increase in greenhouse gas allowances of approximately $30 million and a joint venture investment of approximately $1 million. Greenhouse gas allowances were valued using a market approach based on trading prices for carbon credits on February 28, 2017. Our joint venture investment was valued based on a market approach using a market EBITDA multiple.

F-17

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

(18) Reflects increases for greenhouse gas emissions liabilities of approximately $4 million and a change in accounting policy from the entitlements method to the sales method for gas production imbalances of approximately $200,000, partially offset by a decrease for the current portion of intangibles liabilities of approximately $500,000.

(19) Reflects an increase of the current portion of asset retirement obligations.

(20) Primarily reflects a decrease for asset retirement obligations of approximately $30 million and for intangible liabilities of approximately $6 million, partially offset by an increase for greenhouse gas emissions liabilities of approximately $19 million. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. The intangible liabilities identified on the Effective Date were valued based on a combination of market and incomes approaches and will be amortized over the remaining life of the respective contract. Greenhouse gas emissions liabilities were valued using a market approach based on trading prices for greenhouse gas allowances on February 28, 2017.

(21) Reflects the cumulative impact of the fresh-start accounting adjustments discussed above and the elimination of the Predecessor’s accumulated deficit.

Note 4 – Oil and Natural Gas Properties

Oil and Natural Gas Capitalized Costs

As a result of the application of fresh-start accounting, we recorded our natural gas properties at fair value as of the Effective Date. The fair values of oil and natural gas properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved and unproved properties include estimates of i) reserves ii) future operating and development costs iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates at the time of the valuation and are the most sensitive and subject to change of our inputs. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement.

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	Berry Corp. (Successor) September 30, 2017			Berry LLC (Predecessor) December 31, 2016
	(in thousands)
Proved properties	$	807,646		$	4,262,155
Unproved properties		517,037			764,655
		1,324,683			5,026,810
Less accumulated depletion and amortization		(37,512	)		(2,789,368	)
	$	1,287,171		$	2,237,442

F-18

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Impairment of Proved Properties

We perform impairment tests with respect to our proved properties on a field-by-field basis whenever commodity prices are subject to prolonged declines, reserves estimates change significantly or other significant events occur or management’s plans change with respect to these properties in a manner that may impact our ability to realize recorded volumes. Impairment tests incorporate a number of assumptions involving expectations of undiscounted future cash flows, which can change significantly over time. These assumptions include estimates of future commodity prices, which we base on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future operating and development costs. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value.

During the nine months ended September 30, 2016, we recorded the following non-cash impairment charges associated with proved oil and natural gas properties:

	Berry LLC (Predecessor)
	Nine Months Ended September 30, 2016
	(in thousands)
California operating area	$	984,288
Uinta basin operating area		26,677
East Texas operating area		6,387
	$	1,017,352

We recorded no impairment charges for the periods ended September 30, 2017. The impairment charges in 2016 were due to a decline in commodity prices, changes in expected capital development and a decline in our estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the condensed consolidated statement of operations.

Impairment of Unproved Properties

The unproved amounts are not subject to depreciation, depletion and amortization until they are classified as proved properties. However, if the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past.

Based on the policy described above, we recorded no impairment charges for unproved properties for the periods ended September 30, 2017.

For the nine months ended September 30, 2016, we recorded non-cash impairment charges of approximately $13 million associated with unproved oil and natural gas properties in California. The impairment charges in

F-19

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

2016 were due to a decline in commodity prices and changes in expected capital development. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the condensed consolidated statement of operations.

Note 5 – Debt

The following table summarizes our outstanding debt:

	(Successor) September 30, 2017		(Predecessor) December 31, 2016
	(in thousands)
Current portion of debt:
Pre-Emergence Credit Facility(1)	$	—	$	891,259
Long-term debt:
RBL Credit Facility(2)	$	379,000	$	—
Liabilities subject to compromise:
6.75% senior notes due November 2020(3)	$	—	$	261,100
6.375% senior notes due September 2022(3)	$	—	$	572,700

(1) Due to covenant violations, the Pre-Emergence Credit Facility was classified as current at December 31, 2016.

(2) Variable interest rates of 4.5% and 5.5% at September 30, 2017 and December 31, 2016, respectively.

(3) The Company’s senior notes were classified as liabilities subject to compromise at December 31, 2016.

At September 30, 2017 and December 31, 2016, deferred debt issuance costs were approximately $21 million and $6 million. The amortization of these debt issuance costs is presented in interest expense on the unaudited condensed consolidated income statement.

Fair Value

Our debt is recorded at the carrying amount on the balance sheets. The carrying amount of the RBL Credit Facility approximates fair value because the interest rates are variable and reflective of market rates. The Predecessor’s senior notes had a carrying value and fair value of $833.8 million and $522.2 million, respectively, at December 31, 2016. We used a market approach to determine the fair value of the Predecessor’s senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.

Credit Facilities

2017 Credit Facilities

On the Effective Date, we entered into a credit agreement (“the Emergence Credit Facility”) with Wells Fargo Bank, N.A. as administrative agent and certain lenders. The Emergence Credit Facility provided for a revolving loan with up to $550 million in borrowing commitments, subject to a reserve borrowing base. The initial borrowing base was $550 million with a maturity date of February 27, 2022. Approximately $400 million in borrowings and $6 million in undrawn letters of credit were outstanding under the Emergence Credit Facility

F-20

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

as of the Effective Date. The outstanding borrowings under the Emergence Credit Agreement bore interest at a rate equal to either (i) LIBOR plus an applicable margin ranging from 3.25% to 4.25% per annum, depending on levels of borrowing base usage and (ii) a customary base rate plus an applicable margin ranging from 2.25% to 3.25% per annum, depending on levels of borrowing base usage.

We executed amended and restated mortgages in order to achieve collateral coverage of no less than 95% of the total value of the proved reserves of our oil and natural gas properties.

On July 31, 2017, we entered into a new credit agreement (“RBL Credit Facility”), also with Wells Fargo Bank, N.A. as administrative agent and certain lenders with a commitment of $1.5 billion, subject to a reserve borrowing base, and an initial borrowing base of $500 million. This facility matures on June 29, 2022. The RBL Credit Facility was used to paydown the outstanding borrowings from the Emergence Credit Facility.

The outstanding borrowings under the RBL Credit Facility bear interest at a rate equal to either (i) a customary London interbank offered rate plus an applicable margin ranging from 2.50% to 3.5% per annum, and (ii) a customary base rate plus an applicable margin ranging from 1.5% to 2.5% per annum, in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average daily unused amount of the borrowing availability under the RBL Credit Facility.

The lenders under the RBL Credit Facility hold a mortgage on 85% of the present value of our proven (PDP) oil and gas reserves.

As of September 30, 2017, the financial performance covenants under our RBL Credit Facility were (i) a Maximum Leverage Ratio of 4.0 to 1.0, (ii) a Maximum Current Ratio of 1.0 to 1.0 and (iii) Other Total Debt Incurred of 2% of consolidated net tangible assets. In addition, the RBL Credit Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt.

As of September 30, 2017, we had approximately $100 million of available borrowing capacity under the RBL Credit Facility.

Our borrowing base is re-determined semi-annually on May 1st and November 1st. If we engage in an asset sale or hedge event that exceeds 5% of our borrowing base, then our borrowing base will be reduced by the amount of the asset sale or hedge event.

As of September 30, 2017, per our RBL Credit Facility, we were required to have in place the following commodity hedging coverage with a swap counterparty over our projected notional volumes of crude oil production from PDP reserves, on a monthly basis:

	9/30/2017		Q4 2017		2018		2019
Swaps required by RBL Credit Facility
MBbls		467		415		1,876		1,622
Minimum price	$	49.50	$	43.38	$	44.87	$	45.94

At September 30, 2017, we were in compliance with all financial and other debt covenants.

The terms and conditions of all of our indebtedness are subject to additional qualifications and limitations that are set forth in the relevant governing documents.

F-21

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

As of September 30, 2017 and December 31, 2016, we had letters of credit outstanding of approximately $21 million and $7 million, respectively, under our revolving credit facilities. These letters of credit were issued to support ordinary course of business marketing, insurance, regulatory and other matters.

Pre-Emergence Credit Facility and Predecessor’s Senior Notes

On the Effective Date, pursuant to the terms of the Plan, all outstanding obligations under the Pre-Emergence Credit Facility and the Predecessor’s senior notes were canceled. See Note 2 for additional information.

Predecessor Covenant Violations

Our filing of the Bankruptcy Petitions constituted an event of default that accelerated our obligations under the Pre-Emergence credit facility and our senior notes. For the two months ended February 28, 2017, contractual interest, which was not recorded, on the Unsecured Notes was approximately $9 million. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default.

Senior Unsecured Notes Offering

In February 2018, we closed a private offering (the “2018 Notes Offering”) of $400 million principal amount of 7.000% senior unsecured notes due 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately $392 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the 2018 Notes Offering to repay borrowings under the RBL Facility and will use the remainder for general corporate purposes.

Note 6 – Derivatives

We have hedged a portion of our forecasted production to reduce exposure to fluctuations in oil and natural gas prices and to assist us in complying with covenants in our RBL Credit Facility in the event of price deterioration. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations. We have also hedged our exposure to differentials in certain operating areas but do not currently hedge exposure to natural gas differentials.

Our current hedge positions consist of primarily oil swap contracts, though in the past we have also used collars and three-way collars and hedged our exposure to natural gas and natural gas liquids (NGL) price changes.

We enter into these transactions with respect to a portion of our projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. We do not enter into derivative contracts for speculative trading purposes. We did not designate any of our contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.

We account for our commodity derivatives at fair value on a recurring basis. We determine the fair value of these derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.

F-22

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

As part of our hedging program, we entered into a number of derivative transactions that resulted in the following WTI-based crude oil contracts as of September 30, 2017:

	Q4 2017		Q1 2018		Q2 2018		Q3 2018		Q4 2018		FY 2019		FY 2020
Sold Oil Calls:
Hedged oil volume (MBbls)		150		225		225		225		225		840		390
Weighted average price ($/Bbl)	$	55.00	$	55.00	$	55.00	$	55.00	$	55.00	$	57.32	$	60.00
Oil positions:
Fixed Price Swaps (NYMEX WTI):
Hedged volume (MBbls)		1,335		1,188		1,201		1,214		1,214		4,197		—
Weighted average price ($/Bbl)	$	52.54	$	52.04	$	52.04	$	52.04	$	52.04	$	52.05	$	—
Oil basis differential positions:
ICE Brent-NYMEX WTI basis swaps
Hedged volume (MBbls)		552		360		364		368		368		1,095		—
Weighted average price ($/Bbl)	$	1.24	$	1.21	$	1.21	$	1.21	$	1.21	$	1.17	$	—

We earn a premium on our sold calls at the time of sale. We make settlement payments for prices above the indicated weighted-average price per barrel of WTI. If the calls expire unexercised, no payments are received.

For fixed-price swaps, we make settlement payments for prices above the indicated weighted-average price per barrel of WTI and receive settlement payments for prices below the indicated weighted average price per barrel of WTI.

F-23

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated weighted average price per barrel and receive settlement payments if the difference between Brent and WTI is below the indicated weighted average price per barrel. Our commodity derivatives are measured at fair value using industry-standard models with various inputs including forward prices and all are classified as Level 2 in the required fair value hierarchy for the periods presented. The following tables present the fair values (at gross or net) of our outstanding derivatives as of September 30, 2017 and December 31, 2016:

	Successor
	September 30, 2017
	Balance Sheet Classification		Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheet			Net Fair Value Presented in the Balance Sheet
	(in thousands)
Assets
Commodity Contracts		Current assets	$	7,686		$	(6,715	)	$	971
Commodity Contracts		Non-current assets		13,127			(9,117	)		4,010
Liabilities
Commodity Contracts		Current liabilities		(13,541	)		6,715			(6,826	)
Commodity Contracts		Non-current liabilities		(16,846	)		9,117			(7,729	)
Total derivatives			$	(9,574	)	$	—		$	(9,574	)
	Predecessor
	December 31, 2016
	Balance Sheet Classification		Gross Amounts Recognized at Fair Value			Gross Amounts Offset in the Balance Sheet			Net Fair Value Presented in the Balance Sheet
	(in thousands)
Assets
Commodity Contracts		Current assets	$	119		$	(119	)	$	—
Commodity Contracts		Non-current assets		—			—			—
Liabilities
Commodity Contracts		Current liabilities		(9,015	)		119			(8,896	)
Commodity Contracts		Non-current liabilities		(10,221	)		—			(10,221	)
Total derivatives			$	(19,117	)	$	—		$	(19,117	)

By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We do not receive collateral from our counterparties.

The maximum amount of loss due to credit risk that the we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $21 million at September 30, 2017. We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our RBL Credit Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standards & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives which mitigates the counterparty nonperformance risk somewhat.

F-24

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Gains (Losses) on Derivatives

A summary of gains and losses on the derivatives included on the statements of operations is presented below:

	Berry Corp. (Successor)		Berry, LLC (Predecessor)
	Seven Months Ended September 30, 2017		Two Months Ended February 28, 2017		Nine Months Ended September 30, 2016
			(in thousands)
Gains (losses) on oil and natural gas derivatives	$	5,642	$	12,886	$	1,642
Lease operating expenses(1)		—		—		(4,605	)
Total gains (losses) on oil and natural gas derivatives	$	5,642	$	12,886	$	(2,963	)

(1) Consists of gains and (losses) on derivatives that were entered into in March 2015 to hedge exposure to differentials in consuming areas.

For the seven months ended September 30, 2017 and two months ended February 28, 2017, we received net cash settlements of approximately $10 million and $0.5 million, respectively. For the nine months ended September 30, 2016, we received net cash settlements of approximately $10 million.

Note 7 – Lawsuits, Claims, Commitments and Contingencies

In the normal course of business, we, or our subsidiary, are subject to lawsuits, environmental and other claims and other contingencies that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

On May 11, 2016 our predecessor company filed the Chapter 11 Proceeding. Our bankruptcy case was jointly administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding. On the Effective Date the plan became effective and was implemented. The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims.

In March 2017, Wells Fargo Bank, N.A. (“Wells”), the administrative agent under the Pre-Emergence Credit Facility, filed a motion in the Bankruptcy Court seeking payment of post-petition default interest in the amount of approximately $14 million. We have posted a letter of credit for approximately this amount pending the court’s final order. The court resolved Wells’ motion in our favor on November 13, 2017. Wells filed an appeal on November 27, 2017 and the parties are awaiting the ruling of the appellate court.

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at September 30, 2017 and December 31, 2016 were not material to our balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.

F-25

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

We have certain commitments under contracts, including purchase commitments for goods and services. At September 30, 2017, total purchase obligations were approximately $6.6 million, which included approximately $0.6 million and $6.0 million expected to be paid in 2017 and 2018, respectively. Included in these obligations is a commitment to invest at least $9 million to extend an existing access road in connection with our Piceance assets or construct a new access road, or to pay 50% of the difference between $12 million and the actual amount spent on such access road construction prior to the end of 2018. We have not yet obtained an extension for the road obligation, obtained access to an existing road or started construction of a new access road, and may be unable to extend the deadline and may trigger the payment obligation which, if we were unable to negotiate resolution, would reduce our capital available for investment. Subsequent to September 30, 2017, we entered into agreements to purchase natural gas for our operations in 2018 for approximately $14 million.

We, or our subsidiary, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of September 30, 2017, we are not aware of material indemnity claims pending or threatened against us.

We have entered into operating lease agreements mainly for office space. Lease payments are generally expensed as part of general and administrative expenses. At September 30, 2017, future net minimum lease payments for non-cancelable operating leases (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance and maintenance expense) totaled:

	Amount
	(in thousands)
2017		313
2018		1,268
2019		1,058
2020		—
2021		—
Thereafter		—
Total minimum lease payments	$	2,639

Note 8 – Equity

On the Effective Date, Berry Corp. filed with the Secretary of State of the State of Delaware the Amended and Restated Certificate of Incorporation of Berry Corp. (the “Certificate of Incorporation”) and the Certificate of Designation of Series A Convertible Preferred Stock of Berry Petroleum Corporation (the “Series A Certificate of Designation”). Berry Corp. also adopted the Amended and Restated Bylaws of Berry Petroleum Corporation (the “Bylaws”) on the Effective Date. The Certificate of Incorporation provides that Berry Corp.’s authorized capital stock consists of 750,000,000 shares of common stock, par value $0.001 per share, and 250,000,000 shares of undesignated preferred stock, par value $0.001 per share.

Common Stock

The Plan contemplates the distribution of 40,000,000 shares of common stock in Berry Corp. On the Effective Date, 32,920,000 shares of common stock were distributed, pro rata, to holders of Unsecured Notes claims. The holders of Unsecured Claims are to receive their pro rata share of either (i) 7,080,000 shares of common stock or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. As of the Effective Date, all 7,080,000 shares of common stock distributable to holders of Unsecured Claims were reserved for future distributions pending resolution of disputed claims.

F-26

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Voting Rights – Each share of common stock is entitled to one vote with respect to each matter on which holders of common stock are entitled to vote. Holders of common stock do not have cumulative voting rights.

Dividend Rights – Holders of common stock will be entitled to receive dividends, if any, as may be declared from time to time by our board of directors (“Board”) out of legally available funds.

Liquidation Rights – Upon liquidation, dissolution or winding up of the Company, subject to the rights of the holders of outstanding preferred stock, holders of common stock will be entitled to share ratably in the assets of the Company that are legally available for distribution to holders of common stock after payment of the Company’s debts and other liabilities.

Holders of preferred stock that is outstanding may be entitled to dividend or liquidation preferences over holders of common stock, which means that the Company would have to pay distributions to holders of preferred stock before paying any distributions to holders of common stock.

Preemptive and Conversion Rights – Holders of common stock have no preemptive, conversion or other rights to subscribe for additional shares.

Preferred Stock

On the Effective Date, we issued 35,845,001 shares of preferred stock to participants in the rights offerings extended by the Company to certain holders of claims and in satisfaction of a backstop commitment fee for proceeds of $335 million.

Voting Rights – The Series A Preferred Stock is entitled to vote with holders of common stock, voting together as a single class, with respect to any and all matters subject to a stockholder vote, other than as required by law. Each share of preferred stock is entitled to a number of votes equal to the number of shares of common stock into which the share is convertible as of the record date.

Dividend Rights – Holders of Series A Preferred Stock are entitled to receive, when, as and if declared by the board of directors, cumulative dividends at a rate of 6.00% per annum either in cash or in additional shares of Series A Preferred Stock at the discretion of the board of directors. No dividends have been declared or paid as of September 30, 2017.

Liquidation Rights – If Berry Corp. liquidates, dissolves or winds up, holders of Series A Preferred Stock, in preference to any other series or class of capital stock of Berry Corp., will be entitled to share ratably in Berry Corp.’s assets that are legally available for distribution to holders of Series A Preferred Stock, after payment of its debts and other liabilities, in an amount per share of Series A Preferred Stock equal to the sum of (i) $10.00 plus (ii) any accrued and unpaid regular dividends.

The Series A Preferred Stock ranks senior to each other series or class of capital stock of Berry Corp. with respect to dividend rights, redemption rights, sale, merger or change of control preference and rights on liquidation, dissolution and winding up of the affairs of Berry Corp.

Conversion Rights – The Series A Preferred Stock may be converted into a number of shares of common stock determined by the applicable Conversion Rate (as defined in the Series A Preferred Stock Certificate of Designation (the “Certificate of Designation”)) (i) at the option of the holder at any time and (ii) at the option of Berry Corp. at any time after February 28, 2021, subject to certain conditions, including that the value of a share

F-27

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

of common stock into which a share of Series A Preferred Stock is convertible is equal to or greater than $15.00, based on the volume-weighted average price for any 20-trading day period during the 30 trading days preceding conversion. From the time at which any shares of Series A Preferred Stock are deemed to have been converted, the holder of such converted shares shall no longer be entitled to receive dividends on such Series A Preferred Stock (including any prior accrued or unpaid dividend).

Beneficial Conversion Feature

A beneficial conversion feature exists when the effective conversion price of a convertible security is less than the fair value per share on the commitment date. The conversion price of the preferred stock on the date of issuance was less than the estimated fair value of the common stock distributable under the Plan. Since the preferred stock is not mandatorily redeemable and is immediately convertible, the entire amount of the beneficial conversion feature was recognized immediately. In accordance with GAAP, we recorded a non-cash deemed dividend and a corresponding increase to additional paid in capital of approximately $28 million that is attributable to this beneficial conversion feature. The financial statement impact of the deemed dividend is eliminated in the condensed consolidated statement of equity as adopting fresh-start accounting results in an entity with no beginning retained earnings or accumulated deficit.

Registration Rights Agreement

On the Effective Date, Berry Corp. entered into a registration rights agreement (the “Registration Rights Agreement”) with certain holders of the Unsecured Notes.

The Registration Rights Agreement requires Berry Corp. to file a shelf registration statement with the SEC as soon as practicable following the Effective Date. The shelf registration statement will register the resale, on a delayed or continuous basis, of all Registrable Securities that have been timely designated for inclusion by specified Holders (as defined in the Registration Rights Agreement). Generally, “Registrable Securities” includes (i) common stock issued or to be issued by Berry Corp. under the Plan, (ii) preferred stock that was purchased by the participants in the Berry Rights Offerings and (iii) common stock into which the preferred stock converts, except that “Registrable Securities” does not include securities that have been sold under an effective registration statement or Rule 144 under the Securities Act. The Registration Rights Agreement will terminate when there are no longer any Registrable Securities outstanding.

2017 Omnibus Incentive Plan

On June 15, 2017, the Company adopted the 2017 Omnibus Incentive Plan. Our stock-based compensation program currently consists of restricted stock units and performance restricted stock units available to employees and directors, which are equity-classified awards. The aggregate number of shares of common stock reserved for issuance pursuant to the 2017 Omnibus Incentive Plan is 6,876,500.

The fair value of the restricted stock units is determined based on their estimated fair market value on the date of grant. This value is amortized over the vesting and performance periods. Included in lease operating expenses and general and administrative expenses is stock-based compensation expense of $0.9 million for the seven months ended September 30, 2017.

F-28

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

A summary of the status of changes of unvested shares of restricted stock units under the 2017 Omnibus Incentive Plan is presented below:

	Number of shares			Weighted average Grant Date Fair Value
	(shares in thousands)
February 28, 2017		—
Granted		1,243		$	8.68
Vested		(3	)	$	10.12
Forfeited		(5	)	$	10.12
September 30, 2017		1,235		$	8.68

As of September 30, 2017, there was approximately $9.9 million of total unrecognized compensation cost related to the unvested restricted stock units. This cost is expected to be recognized over a period of approximately three years.

Note 9 – Income taxes

On the Effective Date, upon consummation of the Plan, the Successor became a C Corporation subject to federal and state income taxes. Prior to the consummation of the Plan, the Predecessor was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor.

For the seven months ended September 30, 2017 we recognized an income tax expense of $9 million. The effective tax rate was 39.9%. The effective tax rate differed from the federal statutory rate of 35% due to the impact of state taxes.

Note 10 – Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

Accounts receivable, net, includes allowance for doubtful accounts of $0.9 million and none at September 30, 2017 and December 31, 2016, respectively.

Other current assets reported on the condensed consolidated balance sheets included the following:

	Berry Corp (Successor) September 30, 2017		Berry LLC (Predecessor) December 31, 2016
	(in thousands)
Prepaid expenses	$	5,987	$	4,149
Greenhouse gas allowances		8,508		3,087
Oil inventories, materials and supplies		4,833		3,299
Other		1,627		5,811
Other current assets	$	20,955	$	16,346

F-29

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Other non-current assets at September 30, 2017 included approximately $55 million of greenhouse gas allowances.

Supplemental Cash Flow Information

Supplemental disclosures to the statements of cash flows are presented below:

	Berry Corp (Successor)		Berry LLC (Predecessor)
	Seven Months Ended September 30, 2017		Two Months Ended February 28, 2017		Nine Months Ended September 30, 2016
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	9,586	$	8,057	$	46,034
Cash payments for income taxes	$	1,994	$	—	$	347
Cash payments for reorganization items, net	$	1,001	$	11,838	$	3,138
Non-cash investing activities:
Accrued capital expenditures	$	1,011	$	2,268	$	1,975

For purposes of the condensed consolidated statements of cash flows, we consider all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At September 30, 2017, “restricted cash” of approximately $35 million was classified as a current asset on the condensed consolidated balance sheet and represents cash that will be used to settle certain claims and pay certain professional fees in accordance with the Plan. At December 31, 2016, “restricted cash” of approximately $198 million classified as a non-current asset on the condensed balance sheet represents cash that LINN Energy contributed to Berry LLC in May 2015 to post with Berry LLC’s lenders in connection with the reduction in the Pre-Emergence Credit Facility’s borrowing base, as well as associated interest income. Such restricted cash was used in February 2017 to repay a portion of the borrowings outstanding under the Pre-emergence Credit Facility, which is reflected as a non-cash transaction by the Company.

Note 11 – Related Party Transactions

The Predecessor had no employees. The employees of Linn Operating, Inc. (“Linn Operating”), a subsidiary of LINN Energy, provided services and support to the Company in accordance with an agency agreement and power of attorney between the Company and Linn Operating.

Transition Services and Separation Agreement (“TSSA”)

On the Effective Date, Berry LLC entered into the TSSA with LINN Energy and certain of its subsidiaries to facilitate the separation of Berry LLC’s operations from LINN Energy’s operations. Pursuant to the TSSA, (i) LINN Energy will continue to provide, or cause to be provided, certain administrative, management, operating, and other services and support to the Company during a transitional period following the Effective Date (the “Transition Services”), (ii) the LINN Energy debtors and Berry LLC will separate their previously combined enterprise and (iii) the LINN Energy debtors will transfer to Berry LLC certain assets that relate to Berry LLC’s properties or its business, in each case under the terms and conditions specified in the TSSA.

F-30

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

Under the TSSA, Berry LLC would reimburse LINN Energy for any and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented, in connection with providing the Transition Services. Additionally, Berry LLC would pay to LINN Energy a management fee equal to $6 million per month, prorated for partial months, during the period from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”) and $2.7 million per month, prorated for partial months, from the first day following the Transition Period through the last day of the second full calendar month thereafter (the “Accounting Period”). During the Accounting Period, the scope of the Transition Services would be reduced to specified accounting and administrative functions. The Transition Period under the TSSA ended April 30, 2017, and the Accounting Period ended June 30, 2017.

For the seven months ended September 30, 2017, we incurred management fee expenses of approximately $17 million under the TSSA. Since the agreement commenced on the Effective Date, no expenses were incurred for the periods ended February 28, 2017 or December 31, 2016. At September 30, 2017 and December 31, 2016, we had a receivable due from LINN Energy of approximately $0.8 million and $3.0 million, respectively included in “accounts receivable, net” and approximately $43 million due to LINN Energy included in “liabilities subject to compromise” on the condensed balance sheet at December 31, 2016.

Note 12 – Acquisitions and Divestitures

On July 31, 2017, we divested our 78% working interest in the Hugoton natural gas field located in Southwest Kansas and the Oklahoma Panhandle because we deemed it a non-core asset. This resulted in approximately $235 million of proceeds and a $21 million gain, subject to final settlement adjustments.

Also on July 31, 2017, we acquired the remaining 84% working interest in the South Belridge Hill property located in Kern County, California, in which we previously owned a 16% working interest. We purchased the properties for approximately $257 million, subject to final settlement adjustments.

Note 13- Earnings Per Share

Our Predecessor Company was organized as a limited liability company and, as such, did not issue any stock. Accordingly, we have not presented earnings per share calculations for the Predecessor Company periods.

We calculate basic earnings (loss) per share by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding during each period. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, such as those shares contemplated by the Plan, are considered common shares outstanding and are included in the computation of net income (loss) per share. Accordingly, the 40 million shares of common stock contemplated by the Plan, without regard to actual issuance dates, were included in the computation of net income (loss) per share for the seven months ended September 30, 2017.

We compute basic and diluted earnings per share (EPS) using the two-class method required for participating securities. Certain restricted stock units and performance-based restricted stock units (RSUs) issued to our employees and non-employee directors, are considered participating securities when such shares have non-forfeitable dividend rights at the same rate as common stock. The impact of such participating securities in the periods presented below was not material. In the basic EPS calculation below, the weighted-average number of common shares outstanding excludes outstanding shares related to unvested stock awards. For diluted EPS, the

F-31

BERRY PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) (Continued)

basic shares outstanding are adjusted by adding potentially dilutive securities. No incremental shares of potentially dilutive RSUs were included in the diluted EPS calculation as their effect was antidilutive under the treasury stock method.

The convertible preferred stock is not a participating security, therefore, we calculated diluted EPS using the “if-converted’ method where the preferred dividends are added back to the numerator and the convertible preferred stock is assumed to be converted at the beginning of the period. No incremental shares of convertible preferred stock were included in the diluted EPS calculation as their effect was antidilutive under the “if-converted” method.

	Seven Months Ended September 30, 2017			Two Months Ended February 28, 2017		Nine Months Ended September 30, 2016
	(in thousands except per share amounts)
Basic EPS calculation
Net income	$	13,812			n/a		n/a
less: Undeclared dividends on Series A preferred stock		(12,681	)		n/a		n/a
Net income available to common stockholders	$	1,131			n/a		n/a
Weighted-average shares of common stock outstanding		32,920			n/a		n/a
Shares of common stock distributable to holders of Unsecured Claims (note 2)		7,080			n/a		n/a
Weighted-average common shares outstanding-basic		40,000			n/a		n/a
Basic EPS	$	0.03			n/a		n/a
Diluted EPS calculation
Net income	$	13,812			n/a		n/a
less: Undeclared dividends on Series A preferred stock		(12,681	)		n/a		n/a
Net income available to common stockholders	$	1,131			n/a		n/a
Weighted-average shares of common stock outstanding		32,920			n/a		n/a
Shares of common stock distributable to holders of Unsecured Claims (note 2)		7,080			n/a		n/a
Weighted-average common shares outstanding-basic		40,000			n/a		n/a
Dilutive effect of potentially dilutive securities		—			n/a		n/a
Weighted-average common shares outstanding-diluted		40,000			n/a		n/a
Diluted EPS	$	0.03			n/a		n/a

F-32

Report of Independent Registered Public Accounting Firm

The Board of Directors

Berry Petroleum Corporation:

We have audited the accompanying balance sheets of Berry Petroleum Company, LLC (Debtor-in-Possession) (the “Company”) as of December 31, 2016 and 2015, and the related statements of operations, member’s equity, and cash flows for each of the years in the two-year period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Berry Petroleum Company, LLC (Debtor-in-Possession) as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Company’s Plan of Reorganization (the “Plan”) on January 27, 2017. Confirmation of the Plan resulted in the discharge of debt of the Company and substantially altered rights and interests of debt and equity security holders as provided for in the Plan. The Plan was substantially consummated on February 28, 2017 and the Company emerged from bankruptcy at which time it became a wholly-owned subsidiary of Berry Petroleum Corporation in accordance with the Plan. In connection with its emergence from bankruptcy, the Company adopted fresh-start accounting as of February 28, 2017.

/s/ KPMG LLP

Houston, Texas

May 15, 2017

F-33

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

BALANCE SHEETS

	December 31,
	2016			2015
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	30,483		$	1,023
Accounts receivable – trade, net		51,175			46,053
Derivative instruments		—			13,218
Other current assets		16,346			20,897
Total current assets		98,004			81,191
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		5,026,810			5,011,061
Less accumulated depletion and amortization		(2,789,368	)		(1,596,165	)
		2,237,442			3,414,896
Other property and equipment		123,460			111,495
Less accumulated depreciation		(20,759	)		(12,522	)
		102,701			98,973
Restricted cash		197,793			250,359
Other noncurrent assets		16,110			16,057
		213,903			266,416
Total noncurrent assets		2,554,046			3,780,285
Total assets	$	2,652,050		$	3,861,476
LIABILITIES AND MEMBER’S EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	65,858		$	125,748
Derivative instruments		8,896			2,241
Current portion of long-term debt		891,259			873,175
Other accrued liabilities		3,140			16,735
Total current liabilities		969,153			1,017,899
Derivative instruments		10,221			—
Long-term debt, net		—			845,368
Other noncurrent liabilities		169,160			212,050
Liabilities subject to compromise		1,000,553			—
Commitments and contingencies (Note 9)
Member’s equity:
Additional paid-in capital		2,798,713			2,798,713
Accumulated deficit		(2,295,750	)		(1,012,554	)
		502,963			1,786,159
Total liabilities and member’s equity	$	2,652,050		$	3,861,476

The accompanying notes are an integral part of these financial statements.

F-34

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2016			2015
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	392,345		$	575,031
Electricity sales		23,204			24,544
Gains (losses) on oil and natural gas derivatives		(15,781	)		29,175
Marketing revenues		3,653			5,709
Other revenues		7,570			7,195
		410,991			641,654
Expenses:
Lease operating expenses		185,056			245,155
Electricity generation expenses		17,133			18,057
Transportation expenses		41,619			52,160
Marketing expenses		3,100			3,809
General and administrative expenses		79,236			85,993
Depreciation, depletion and amortization		178,223			251,371
Impairment of long-lived assets		1,030,588			853,810
Taxes, other than income taxes		25,113			70,593
Gains on sale of assets and other, net		(109	)		(1,919	)
		1,559,959			1,579,029
Other income and (expenses):
Interest expense, net of amounts capitalized		(61,268	)		(85,818	)
Gain on extinguishment of debt		—			11,209
Other, net		(182	)		(3,261	)
		(61,450	)		(77,870	)
Reorganization items, net		(72,662	)		—
Loss before income taxes		(1,283,080	)		(1,015,245	)
Income tax expense (benefit)		116			(68	)
Net loss	$	(1,283,196	)	$	(1,015,177	)

The accompanying notes are an integral part of these financial statements.

F-35

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

STATEMENTS OF MEMBER’S EQUITY

	Additional Paid- In Capital			Accumulated Income (Deficit)			Total Member’s Equity
	(in thousands)
December 31, 2014		2,416,381			2,623			2,419,004
Capital contributions from affiliate		471,278			—			471,278
Distributions to affiliate		(88,946	)		—			(88,946	)
Net loss		—			(1,015,177	)		(1,015,177	)
December 31, 2015		2,798,713			(1,012,554	)		1,786,159
Net loss		—			(1,283,196	)		(1,283,196	)
December 31, 2016	$	2,798,713		$	(2,295,750	)	$	502,963

The accompanying notes are an integral part of these financial statements.

F-36

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2016			2015
	(in thousands)
Cash flow from operating activities:
Net loss	$	(1,283,196	)	$	(1,015,177	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		178,223			251,371
Impairment of long-lived assets		1,030,588			853,810
Gain on extinguishment of debt		—			(11,209	)
Amortization and write-off of deferred financing fees		1,849			3,750
Gains on sale of assets and other, net		(1,064	)		(961	)
Deferred income taxes		(11	)		(68	)
Reorganization items, net		43,289			—
Derivatives activities:
Total (gains) losses		20,386			(36,068	)
Cash settlements		8,007			68,770
Cash settlements on canceled derivatives		1,701			—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		(6,556	)		59,941
Decrease in other assets		1,962			18,724
Increase (decrease) in accounts payable and accrued expenses		22,101			(62,755	)
Decrease in other liabilities		(4,934	)		(7,610	)
Net cash provided by operating activities		12,345			122,518
Cash flow from investing activities:
Development of oil and natural gas properties		(21,988	)		(32,633	)
Purchases of other property and equipment		(12,808	)		(17,741	)
Settlement of advance to affiliate		—			129,217
Decrease in restricted cash		53,418			—
Proceeds from sale of properties and equipment and other		194			22,525
Net cash provided by investing activities		18,816			101,368
Cash flow from financing activities:
Repayments of debt		(1,701	)		(355,418	)
Financing fees and other, net		—			(1,363	)
Capital contributions from affiliate		—			221,278
Distributions to affiliate		—			(88,946	)
Net cash used in financing activities		(1,701	)		(224,449	)
Net increase (decrease) in cash and cash equivalents		29,460			(563	)
Cash and cash equivalents:
Beginning		1,023			1,586
Ending	$	30,483		$	1,023

The accompanying notes are an integral part of these financial statements.

F-37

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS

Note 1 – Basis of Presentation and Significant Accounting Policies

“Berry Corp.” refers to Berry Petroleum Corporation, a Delaware corporation that is the sole member of Berry LLC.

“Berry LLC” refers to Berry Petroleum Company, LLC, a Delaware limited liability company that is wholly owned by Berry Corp.

As the context may require, the “Company” refers to (i) Berry Corp. and its consolidated subsidiaries, including Berry LLC, as a whole, or (ii) either Berry Corp. or Berry LLC on an individual basis. References to historical activities of the “Company” prior to February 28, 2017, refer to activities of Berry LLC.

“LINN Energy” refers to Linn Energy, LLC, a Delaware limited liability company that formerly wholly owned, indirectly, Berry LLC.

Subsequent events have been evaluated through May 15, 2017, the date these financial statements were issued. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the financial statements and related footnotes.

Nature of Business

Berry Corp. is an independent oil and natural gas company that incorporated under Delaware law on February 13, 2017. Berry Corp. operates through its wholly-owned subsidiary, Berry LLC.

Berry LLC’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until December 2013. On December 16, 2013, an affiliate of LINN Energy, LinnCo, LLC (“LinnCo”), acquired all of the outstanding common shares of Berry Petroleum Company and contributed Berry Petroleum Company to LINN Energy in exchange for LINN Energy units. In connection with its acquisition by LINN Energy, Berry Petroleum Company was converted from a Delaware corporation into a Delaware limited liability company and changed its name to “Berry Petroleum Company, LLC.” Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, became Berry LLC’s sole member.

As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), LINN Energy, LinnCo and Berry LLC (collectively, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16-60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy as a stand-alone company separate from LINN Energy effective February 28, 2017.

The Company’s properties are located in the United States (“U.S.”), in Kansas and the Oklahoma Panhandle (Hugoton basin), California (San Joaquin Valley and Los Angeles basins), Utah (Uinta basin), Colorado (Piceance basin) and east Texas.

F-38

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Principles of Reporting

The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

The financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), member’s equity or cash flows.

Bankruptcy Accounting

The financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s balance sheet at December 31, 2016. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less.

The accompanying financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on member’s equity accounts of any changes that may be made to the Company’s capitalization; or (iv) the effect on operations of any changes that may be made to the Company’s business.

Use of Estimates

The preparation of the accompanying financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

F-39

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Recently Issued Accounting Standards

In November 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address the diversity in practice in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statements of cash flows.

In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The Company expects the adoption of this ASU to impact its balance sheets resulting from an increase in both assets and liabilities related to the Company’s leasing activities.

In November 2015, the FASB issued an ASU that is intended to simplify the presentation of deferred taxes by requiring that all deferred taxes be classified as noncurrent, presented as a single noncurrent amount for each tax-paying component of an entity. The ASU is effective for fiscal years beginning after December 15, 2016; however, the Company early adopted it on January 1, 2016, on a retrospective basis. The adoption of this ASU did not have a material impact on the Company’s financial statements or related disclosures.

In April 2015, the FASB issued an ASU that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company adopted this ASU on January 1, 2016, on a retrospective basis. The adoption of this ASU had no impact on the Company’s financial statements or related disclosures, as the Company’s only debt issuance costs relate to the Prior Credit Facility, as defined in Note 2, which were not reclassified.

In August 2014, the FASB issued an ASU that provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for the annual periods and interim periods thereafter, and the Company adopted this ASU on December 31, 2016. The adoption of this ASU had no impact on the Company’s financial statements or related disclosures.

In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company does not plan on early adopting this ASU. The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures.

F-40

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Cash Equivalents

For purposes of the statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.

Accounts Receivable — Trade, Net

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The Company had no allowance for doubtful accounts at December 31, 2016, or December 31, 2015.

Inventories

Materials, supplies and commodity inventories are valued at the lower of average cost or market. Inventories also include California carbon allowance instruments.

Oil and Natural Gas Properties

Proved Properties

The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $1 million and $2 million for the years ended December 31, 2016, and December 31, 2015, respectively.

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to

F-41

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.

Based on the analysis described above, the Company recorded the following noncash impairment charges associated with proved oil and natural gas properties:

	Year Ended December 31,
	2016		2015
	(in thousands)
California operating area	$	984,288	$	537,511
Uinta basin operating area		26,677		111,339
East Texas operating area		6,387		78,437
Piceance basin operating area		—		55,344
	$	1,017,352	$	782,631

The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the statements of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past.

Based on the analysis described above, for the years ended December 31, 2016, and December 31, 2015, the Company recorded noncash impairment charges of approximately $13 million and $71 million, respectively, associated with unproved oil and natural gas properties in California.

The impairment charges in 2016 and 2015 were primarily due to a decline in commodity prices and changes in expected capital development. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the statements of operations.

F-42

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Other Property and Equipment

Other property and equipment includes natural gas gathering systems, pipelines, furniture and office equipment, buildings, vehicles, information technology equipment, software and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from ten to 39 years for buildings and leasehold improvements and three to 30 years for plant and pipeline, drilling and other equipment.

Restricted Cash

At December 31, 2016, and December 31, 2015, “restricted cash” on the balance sheets includes approximately $198 million and $250 million, respectively, related to the $250 million that LINN Energy contributed to Berry LLC in May 2015 to post with Berry LLC’s lenders in connection with the reduction in the Prior Credit Facility’s borrowing base, as well as associated interest income.

Derivative Instruments

Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices. The Company also, from time to time, has entered into derivative contracts for a portion of its natural gas consumption. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.

The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars, and may enter into put option contracts in the future. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes.

A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.

Derivative instruments are recorded at fair value and included on the balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit

F-43

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives. See Note 5 and Note 6 for additional details about the Company’s derivative financial instruments.

Other Current Assets

“Other current assets” reported on the balance sheets include the following:

	December 31,
	2016		2015
	(in thousands)
Prepaid expenses	$	4,149	$	1,903
California carbon allowance inventories		3,087		7,073
Oil inventories		3,299		3,446
Deferred financing fees		5,613		8,108
Other		198		367
Other current assets	$	16,346	$	20,897

Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2016, and December 31, 2015, net deferred financing fees of approximately $6 million and $8 million, respectively, are included in “other current assets” on the balance sheets. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense.

For the years ended December 31, 2016, and December 31, 2015, amortization expense of approximately $2 million and $3 million, respectively, is included in “interest expense, net of amounts capitalized” on the statements of operations. For the year ended December 31, 2015, approximately $3 million were written off to expense and included in “other, net” on the statements of operations related to amendments of the Prior Credit Facility. No fees were written off to expense during the year ended December 31, 2016.

Business and Credit Concentrations

The Company maintains its cash in bank deposit accounts which at times may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash.

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that the loss of any one of its major purchasers would not have a material adverse effect on its financial condition, results of operations or net cash provided by operating activities.

For the year ended December 31, 2016, the Company’s two largest customers represented approximately 34% and 28% of the Company’s oil, natural gas and NGL sales. For the year ended December 31, 2015, the Company’s three largest customers represented approximately 24%, 23% and 20% of the Company’s oil, natural gas and NGL sales. For the years ended December 31, 2016, and December 31, 2015, 100% of electricity sales were attributable to two customers.

F-44

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

At December 31, 2016, trade accounts receivable from two customers represented approximately 29% and 21% of the Company’s receivables. At December 31, 2015, trade accounts receivable from three customers represented approximately 24%, 22% and 11% of the Company’s receivables.

Revenue Recognition

Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. In addition, the Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses.

Electricity Cost Allocation

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations in California and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus certain direct costs of producing steam.

Fair Value of Financial Instruments

The carrying values of the Company’s receivables, payables and Prior Credit Facility are estimated to be substantially the same as their fair values at December 31, 2016, and December 31, 2015. See Note 4 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 6 for details about the fair value of the Company’s derivative financial instruments.

Income Taxes

Prior to the consummation of the Plan, as defined below, the Company was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its members. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, the Company was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Company.

F-45

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Supplemental Disclosures to Statements of Cash Flows

Supplemental disclosures to the statements of cash flows are presented below:

	Year Ended December 31,
	2016		2015
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	57,759	$	86,226
Cash payments for income taxes	$	347	$	—
Cash payments for reorganization items, net	$	19,116	$	—
Noncash investing activities:
Accrued capital expenditures	$	2,266	$	10,551

For the year ended December 31, 2015, LINN Energy spent approximately $165 million on capital expenditures in respect of Berry LLC’s operations. Berry LLC recorded the $165 million to oil and natural gas properties with an offset to the advance due from LINN Energy. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million to Berry LLC.

In May 2015, LINN Energy made a capital contribution of $250 million to Berry LLC which was deposited on Berry LLC’s behalf and posted as restricted cash with Berry LLC’s lenders in connection with the reduction of its borrowing base.

During the year ended December 31, 2016, approximately $20 million in letters of credit draws were made from the Prior Credit Facility as requested by certain vendors owed prepetition amounts from the Company.

Note 2 – Chapter 11 Proceedings and Covenant Violations

Chapter 11 Proceedings

On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16-60040.

In December 2016, Berry LLC and Linn Acquisition Company, LLC, on the one hand, and the LINN and its other affiliated debtors, on the other hand, filed separate plans of reorganization with the Bankruptcy Court. The “Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC” (the “Plan”) was filed on December 13, 2016. On January 27, 2017, the Bankruptcy Court entered its confirmation order (the “Confirmation Order”) approving and confirming the Plan.

On February 28, 2017, the Plan became effective and was implemented in accordance with its terms. Among other transactions, Linn Acquisition Company, LLC transferred 100% of Berry LLC’s outstanding membership interests to Berry Corp. As a result, Berry LLC emerged from bankruptcy as a wholly-owned subsidiary of Berry Corp., separate from LINN Energy and its affiliates.

F-46

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Plan of Reorganization

On the Effective Date, the Company consummated the following reorganization transactions in accordance with the Plan:

• Linn Acquisition Company, LLC transferred 100% of the outstanding membership interests in Berry LLC to Berry Corp. pursuant to an Assignment Agreement. Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.

• The holders of claims under the Company’s Second Amended and Restated Credit Agreement, dated November 15, 2010, by and among Berry LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and certain lenders, (as amended, the “Prior Credit Facility”), received (i) their pro rata share of a cash paydown and (ii) pro rata participation in the Credit Facility. As a result, all outstanding obligations under the Prior Credit Facility were canceled and the agreements governing these obligations were terminated.

• Berry LLC, as borrower, entered into the Credit Facility with the holders of claims under the Prior Credit Facility, as lenders, and Wells Fargo Bank, N.A, as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments. For additional information about the Credit Facility, see “Financing Activities” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

• The holders of the Company’s 6.75% senior notes due 2020, issued by Berry LLC pursuant to a Second Supplemental Indenture, dated November 1, 2010, and 6.375% senior notes due 2022, issued by Berry LLC pursuant to a Third Supplemental Indenture, dated March 9, 2012 (collectively, the “Unsecured Notes”), received their pro rata share of either (i) a pool of shares of common stock in Berry Corp. or, for those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”) and (ii) specified rights to participate in a two-tranche offering of rights to purchase Series A Preferred Stock at an aggregate purchase price of $335 million (as further defined in the Plan, the “Berry Rights Offerings”). As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.

• The holders of unsecured claims against the Company (other than the Unsecured Notes) (the “Unsecured Claims”) received their pro rata share of either (i) a pool of shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. As a result, all outstanding obligations under the Unsecured Notes and the indentures governing such obligations were canceled and the obligations arising from the Unsecured Claims were extinguished.

• Berry LLC settled all intercompany claims against the LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy.

Bank RSA

Prior to the Petition Date, on May 10, 2016, the Debtors entered into a restructuring support agreement (“Bank RSA”) with certain holders (“Consenting Bank Creditors”) collectively holding or controlling at least 66.67% by aggregate outstanding principal amounts under (i) the Prior Credit Facility and (ii) LINN Energy’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”). The Bank RSA set forth, subject to certain conditions, the commitment of the Consenting Bank Creditors to support a comprehensive restructuring

F-47

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

of the Debtors’ long-term debt. The Bank RSA provided that the Consenting Bank Creditors would support the use of Berry LLC’s cash collateral under specified terms and conditions, including adequate protection terms. The Bank RSA required the Debtors and the Consenting Bank Creditors to, among other things, support and not interfere with consummation of the restructuring transactions contemplated by the Bank RSA and, as to the Consenting Bank Creditors, vote their claims in favor of the Plan.

Liabilities Subject to Compromise

The Company’s balance sheet includes amounts classified as “liabilities subject to compromise,” which represent prepetition liabilities that have been allowed, or that the Company anticipates will be allowed, as claims in its Chapter 11 case. The amounts represent the Company’s current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities the Company has estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

The following table summarizes the components of liabilities subject to compromise included on the balance sheet:

	Year Ended December 31, 2016
	(in thousands)
Accounts payable and accrued expenses	$	151,515
Accrued interest payable		15,238
Debt		833,800
Liabilities subject to compromise	$	1,000,553

Reorganization Items, Net

The Company has incurred and is expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.

The following table summarizes the components of reorganization items included on the statement of operations:

	Year Ended December 31, 2016
	(in thousands)
Legal and other professional advisory fees	$	(30,130	)
Unamortized premiums		10,923
Terminated contracts		(55,148	)
Other		1,693
Reorganization items, net	$	(72,662	)

F-48

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Effect of Filing on Creditors

Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Although the filing of Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors were stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. The Company did not record interest expense on its senior notes for the period from May 12, 2016 through December 31, 2016. For that period, unrecorded contractual interest was approximately $35 million.

Covenant Violations

The Company’s filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under its Prior Credit Facility and its senior notes. Additionally, other events of default, including cross-defaults, occurred, including the failure to make interest payments on Berry LLC’s senior notes and the receipt of a going concern explanatory paragraph from Berry LLC’s independent registered public accounting firm on Berry LLC’s financial statements for the year ended December 31, 2015. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against Berry LLC as a result of any default. See Note 4 for additional details about the Berry LLC’s debt.

Prior Credit Facility

The Prior Credit Facility contained a requirement to deliver audited financial statements without a going concern or like qualification or exception. Consequently, the filing of Berry LLC’s 2015 Annual Report on Form 10-K which included a going concern explanatory paragraph resulted in a default under the Prior Credit Facility as of the filing date, March 28, 2016, subject to a 30 day grace period.

On April 12, 2016, Berry LLC entered into an amendment to the Prior Credit Facility. The amendment provided for, among other things, an agreement that (i) certain events would not become defaults or events of default until May 11, 2016, (ii) the borrowing base would remain constant until May 11, 2016, unless reduced as a result of swap agreement terminations or collateral sales, (iii) Berry LLC would have access to $45 million in cash that was previously restricted in order to fund ordinary course operations and (iv) Berry LLC, the administrative agent and the lenders would negotiate in good faith the terms of a restructuring support agreement in furtherance of a restructuring of the capital structure of Berry LLC. As a condition to closing the amendment, Berry LLC provided control agreements over certain deposit accounts.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated Berry LLC’s obligations under the Prior Credit Facility. However, under the Bankruptcy Code, the creditors under this debt agreement were stayed from taking any action against Berry LLC as a result of the default.

Senior Notes

Berry LLC deferred making an interest payment totaling approximately $18 million due March 15, 2016, on Berry LLC’s 6.375% senior notes due September 2022, which resulted in Berry LLC being in default under these senior notes. The indenture governing the notes provided Berry LLC a 30 day grace period to make the interest payment.

F-49

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

On April 14, 2016, within the 30 day interest payment grace period provided for in the indenture governing the notes, the Company made an interest payment of approximately $18 million in satisfaction of its obligations.

The Company failed to make interest payments due on its senior notes subsequent to April 14, 2016.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the indentures governing the senior notes. However, under the Bankruptcy Code, holders of the senior notes were stayed from taking any action against the Company as a result of the default.

Note 3 – Divestiture

On November 14, 2014, the Company, along with a subsidiary of LINN Energy, completed the sale of certain of its Wolfberry properties in Ector and Midland counties in the Permian basin to Fleur de Lis Energy, LLC (“Permian basin Assets Sale”). Cash proceeds from the sale of these properties were approximately $352 million.

The net cash proceeds from the Permian basin Assets Sale were advanced by the Company to a subsidiary of LINN Energy. These proceeds were required to be used by LINN Energy on capital expenditures in respect of Berry LLC’s operations, to repay Berry LLC’s indebtedness or as otherwise permitted under the terms of Berry LLC’s indentures and Prior Credit Facility. During the twelve months ended September 30, 2015, LINN Energy spent approximately $223 million, including approximately $58 million in 2014, on capital expenditures in respect of Berry LLC’s operations. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million to Berry LLC. In October 2015, Berry LLC used that cash to repay borrowings under its Prior Credit Facility.

Note 4 – Debt

The following summarizes the Company’s outstanding debt:

	December 31,
	2016			2015
	(in thousands, except percentages)
Prior Credit Facility(1)	$	891,259		$	873,175
6.75% senior notes due November 2020		261,100			261,100
6.375% senior notes due September 2022		572,700			572,700
Net unamortized premiums(2)		—			11,568
Total debt, net		1,725,059			1,718,543
Less current portion(3)		(891,259	)		(873,175	)
Less liabilities subject to compromise(4)		(833,800	)		—
Total long-term debt, net	$	—		$	845,368

(1) Variable interest rates of 5.50% and 3.17% at December 31, 2016, and December 31, 2015, respectively.

(2) Approximately $11 million in premiums were written off to reorganization items in connection with the filing of the Bankruptcy Petition.

(3) Due to existing and anticipated covenant violations, the Prior Credit Facility was classified as current at December 31, 2016, and December 31, 2015.

(4) The Company’s senior notes were classified as liabilities subject to compromise at December 31, 2016.

F-50

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Fair Value

The Company’s debt is recorded at the carrying amount on the balance sheets. The carrying amount of the Prior Credit Facility approximates fair value because the interest rate is variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.

	December 31, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Senior notes, net	$	833,800	$	522,167	$	845,368	$	200,249

Prior Credit Facility

The Prior Credit Facility provides for a senior secured revolving credit facility, subject to the then-effective borrowing base. The maturity date is April 2019. At December 31, 2016, the Company had approximately $898 million in total borrowings outstanding (including outstanding letters of credit) under the Prior Credit Facility and there was no remaining availability.

See Note 2 for details of the amendment to the Prior Credit Facility entered into on April 12, 2016.

Redetermination of the borrowing base under the Prior Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually. The Company’s obligations under the Prior Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry LLC is required to maintain: 1) mortgages on properties representing at least 90% of the present value of oil and natural gas properties included on its most recent reserve report, and 2) an EBITDAX to Interest Expense ratio of at least 2.0 to 1.0 currently, 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and 2.5 to 1.0 thereafter. In accordance with the amendment described in Note 2, the lenders had agreed that the failure to maintain the EBITDAX to Interest Expense ratio would not result in a default or event of default until May 11, 2016.

At the Company’s election, interest on borrowings under the Prior Credit Facility is determined by reference to either the LIBOR plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Prior Credit Facility) or a Base Rate (as defined in the Prior Credit Facility) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Prior Credit Facility). Interest is generally payable monthly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at the LIBOR. The Company is required to pay a commitment fee to the lenders under the Prior Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the maximum commitment amount of the lenders.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Prior Credit Facility. However, under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of the default. The automatic stay under the Bankruptcy Code did not apply to letters of credit issued under the Prior Credit Facility. During the year ended December 31, 2016, approximately $20 million in letters of credit draws were made from the Prior Credit Facility.

F-51

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Repurchases of Senior Notes

The Company made no repurchases of its senior notes during the year ended December 31, 2016. During the year ended December 31, 2015, the Company repurchased, on the open market and through a privately negotiated transaction, approximately $65 million of its outstanding senior notes including approximately $39 million of its 6.75% senior notes due November 2020 and approximately $26 million of its 6.375% senior notes due September 2022. In connection with the repurchases, the Company paid approximately $55 million in cash and recorded a gain on extinguishment of debt of approximately $11 million for the year ended December 31, 2015.

Senior Notes Covenants

The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions or dividends on its equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of the Company’s assets.

In addition, any cash generated by the Company is currently being used by the Company to fund its activities. Historically, to the extent that the Company generated cash in excess of its needs and determined to distribute such amounts to LINN Energy, the indentures governing the Company’s senior notes limited the amount it could distribute to LINN Energy to the amount available under a “restricted payments basket,” and the Company could not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Company’s indentures. During the pendency of the bankruptcy proceedings, the Company did not distribute cash to LINN Energy using the restricted payments basket.

The Company may from time to time seek to repurchase its outstanding debt through open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, may be material and will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the senior notes. However, under the Bankruptcy Code, holders of the senior notes were stayed from taking any action against the Company as a result of the default.

Covenant Violations

The Company’s filing of the Bankruptcy Petitions described in Note 2 constituted an event of default that accelerated the Company’s obligations under its Prior Credit Facility and its senior notes. Additionally, other events of default, including cross-defaults, occurred, including the failure to make interest payments on the Company’s senior notes and the receipt of a going concern explanatory paragraph from the Company’s independent registered public accounting firm on the Company’s financial statements for the year ended December 31, 2015. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of any default.

F-52

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 5 – Derivatives

Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices. The Company also, from time to time, has entered into derivative contracts for a portion of its natural gas consumption. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.

The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars. Swap contracts are designed to provide a fixed price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.

The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 6 for fair value disclosures about oil and natural gas commodity derivatives.

The following table presents derivative positions for the periods indicated as of December 31, 2016:

	2017		2018		2019
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (MBbls)		3,650		2,920		2,555
Average price ($/Bbl)	$	54.33	$	54.30	$	54.28

In accordance with a Bankruptcy Court order dated August 16, 2016, the Company was authorized to enter into postpetition hedging arrangements. During the year ended December 31, 2016, the Company entered into commodity derivative contracts consisting of oil swaps for January 2017 through December 2019.

In May 2016 and July 2016, as a result of the Chapter 11 proceedings, the Company’s counterparties canceled (prior to the contract settlement dates) all of the Company’s then-outstanding derivative contracts and the Company received net cash proceeds of approximately $2 million. The net cash proceeds received were used to make permanent repayments of a portion of the borrowings outstanding under the Prior Credit Facility.

The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month. The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month.

F-53

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Balance Sheet Presentation

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis:

	December 31,
	2016		2015
	(in thousands)
Assets:
Commodity derivatives	$	119	$	13,807
Liabilities:
Commodity derivatives	$	19,236	$	2,830

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company does not receive collateral from its counterparties.

The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $119,000 at December 31, 2016. The Company minimizes the credit risk in derivative instruments by (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting arrangements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains (Losses) on Derivatives

A summary of gains and losses on the derivatives included on the statements of operations is presented below:

	Year Ended December 31,
	2016			2015
	(in thousands)
Gains (losses) on oil and natural gas derivatives	$	(15,781	)	$	29,175
Lease operating expenses(1)		(4,605	)		6,893
Total gains (losses) on oil and natural gas derivatives	$	(20,386	)	$	36,068

(1) Consists of gains and (losses) on derivatives were entered into in March 2015 to hedge exposure to differentials in consuming areas.

For the years ended December 31, 2016, and December 31, 2015, the Company received net cash settlements of approximately $10 million and $69 million, respectively.

F-54

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 6 – Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 5) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives.

Fair Value Hierarchy

In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Financial assets and liabilities recorded in the balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1 Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2 Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives).

Level 3 Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

F-55

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	December 31, 2016
	Level 2		Netting(1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	119	$	(119	)	$	—
Liabilities:
Commodity derivatives	$	19,236	$	(119	)	$	19,117
Assets:
Commodity derivatives	$	13,807	$	(589	)	$	13,218
Liabilities:
Commodity derivatives	$	2,830	$	(589	)	$	2,241

(1) Represents counterparty netting under agreements governing such derivatives.

Note 7 – Other Property and Equipment

Other property and equipment consists of the following:

	December 31,
	2016			2015
	(in thousands)
Natural gas plant and pipeline	$	108,701		$	96,771
Buildings and leasehold improvements		5,891			5,884
Vehicles		4,588			4,647
Drilling and other equipment		200			113
Furniture and office equipment		3,879			3,879
Land		201			201
		123,460			111,495
Less accumulated depreciation		(20,759	)		(12,522	)
	$	102,701		$	98,973

Note 8 – Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

F-56

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

The following table presents a reconciliation of the Company’s asset retirement obligations:

	December 31,
	2016			2015
	(in thousands)
Asset retirement obligations at beginning of year	$	137,563		$	121,760
Liabilities added from drilling		113			1,270
Settlements		(4,891	)		(683	)
Current year accretion expense		7,468			6,897
Revision of estimates		1,545			8,319
Asset retirement obligations at end of year	$	141,798		$	137,563

Note 9 – Commitments and Contingencies Operating Leases and Other Commitments

The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2020. The Company recognized expense under operating leases of approximately $2 million and $6 million for the years ending December 31, 2016, and December 31, 2015, respectively.

The following table presents the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2016:

	Total		2017		2018		2019		2020		2021		Thereafter
	(in thousands)
Operating leases(1)	$	3,555	$	1,237	$	1,263	$	1,055	$	—	$	—	$	—
Firm natural gas transportation contracts(2)		11,301		1,711		1,751		1,715		1,758		1,717		2,649
Other commitments(3)		2,357		2,357		—		—		—		—		—
Total	$	17,213	$	5,305	$	3,014	$	2,770	$	1,758	$	1,717	$	2,649

(1) Operating leases relate primarily to obligations associated with the Company’s office facilities and vehicles.

(2) The Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas for use in the Company’s cogeneration and conventional steam generation facilities. The remaining terms of these contracts range from approximately five to seven years and require a minimum monthly charge regardless of whether the contracted capacity is used or not.

(3) Other commitments relate primarily to cogeneration facility management services and equipment rental obligations.

Carry and Earning Agreement

In January 2011, the Company entered into an amendment relating to certain contractual obligations to a third-party co-owner of certain Piceance basin assets in Colorado. The amendment waives a $200,000 penalty for each well not spud by February 2011 and requires the Company to reassign to such third party, by January 31, 2020, all of the interest acquired by the Company from the third party in each 160-acre tract in which the Company has not drilled and completed a well that is producing or capable of producing from a designated formation, or deeper formation, on January 1, 2020. The amendment also requires the Company to pay the first $9 million of costs incurred in connection with the construction of either an extension of the existing access road or a new access road, including the third party’s 50% share. Pursuant to the terms of a further amendment effective September 30, 2015, if by September 30, 2017, the Company does not expend $9 million on the

F-57

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

construction of either the extension of the existing access road or a new access road, the Company is obligated to pay the third party 50% of the difference between $12 million and the actual amount expended on road construction as of such date. Under the terms of the 2015 amendment, this deadline is subject to further extension to no later than December 31, 2017. Due to the need to obtain regulatory approvals, among other reasons, the Company has not yet commenced construction of either an extension of the existing access road or a new access road and may be unable to do so by the extended deadline, thus triggering the payment of the obligation to the third party.

Environmental Matters

The Company has no material accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in material costs to the Company.

Legal Matters

On May 11, 2016, the Debtors filed the Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16-60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order approving and confirming the Plan. On the Effective Date, the Plan became effective and was implemented in accordance with its terms. The Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.

The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. The Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.

The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

During the years ended December 31, 2016, and December 31, 2015, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Note 10 – Income Taxes

Prior to the consummation of the Plan, the Company was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, the Company was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not

F-58

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

given to federal and state income taxes for the operations of the Company, except as set forth in the tables below. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the statements of operations.

	Year Ended December 31,
	2016			2015
	(in thousands)
Current state taxes	$	127		$	—
Deferred state taxes		(11	)		(68	)
	$	116		$	(68	)

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:

	Year Ended December 31,
	2016			2015
	(in thousands)
Federal statutory rate		35	%		35	%

	Year Ended December 31,
	2016			2015
	(in thousands)
Income excluded from nontaxable entities		(35	)		(35	)
Effective rate		—	%		—	%

The effective tax rate was zero for the years ended December 31, 2016, and December 31, 2015, as the Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas.

At December 31, 2016, and December 31, 2015, the Company had net deferred tax assets of approximately $9,000 and net deferred tax liabilities of approximately $1,000, respectively. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2016, or December 31, 2015. The tax years of 2014 through 2016 remain open to examination for income tax purposes in the state of Texas.

F-59

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

NOTES TO FINANCIAL STATEMENTS (Continued)

Note 11 – Related Party Transactions

LINN Energy

As of December 31, 2016, the Company had no employees. The employees of Linn Operating, Inc. (“Linn Operating”), provided services and support to the Company in accordance with an agency agreement and power of attorney between the Company and Linn Operating. For the years ended December 31, 2016, and December 31, 2015, the Company incurred management fee expenses of approximately $69 million and $78 million, respectively, for services provided by Linn Operating. The Company also had accounts receivable due from LINN Energy of approximately $3 million included in “accounts receivable – trade, net” and accounts payable due to LINN Energy of approximately $9 million included in “accounts payable and accrued expenses” on the balance sheets at December 31, 2016, and December 31, 2015, respectively. In addition, the Company had approximately $43 million due to LINN Energy included in “liabilities subject to compromise” on the balance sheet at December 31, 2016.

During the year ended December 31, 2015, LINN Energy made capital contributions of approximately $471 million to Berry LLC, including $250 million which was deposited on Berry LLC’s behalf and posted as restricted cash with Berry LLC’s lenders in connection with the reduction of its borrowing base in May 2015.

The Company made no cash distributions to LINN Energy during the year ended December 31, 2016. During the year ended December 31, 2015, the Company made cash distributions of approximately $89 million to LINN Energy. In addition, in 2014, the Company advanced approximately $352 million, to a subsidiary of LINN Energy, of net cash proceeds from the Permian basin Assets Sale. These proceeds were required to be used by LINN Energy on capital expenditures in respect of Berry LLC’s operations, to repay Berry LLC’s indebtedness or as otherwise permitted under the terms of Berry LLC’s indentures and Prior Credit Facility. During the twelve months ended September 30, 2015, LINN Energy spent approximately $223 million, including approximately $58 million in 2014, on capital expenditures in respect of Berry LLC’s operations. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million to Berry LLC. In October 2015, Berry LLC used that cash to repay borrowings under its Prior Credit Facility.

Other

One of LINN Energy’s former directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. The Company incurred no significant expenditures related to services rendered by Superior and its subsidiaries for the year ended December 31, 2016. For the year ended December 31, 2015, the Company incurred expenditures of approximately $562,000 related to services rendered by Superior and its subsidiaries.

F-60

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

SUPPLEMENTAL OIL & NATURAL GAS DATA

(Unaudited)

The following discussion and analysis should be read in conjunction with the “Financial Statements” and “Notes to Financial Statements,” which are included in this prospectus in “Financial Statements and Supplementary Data.”

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:

	Year Ended December 31,
	2016			2015
	(in thousands)
Property acquisition costs:
Proved	$	1,545		$	—
Unproved		—			—
Exploration costs		—			—
Development costs		13,456			130,276
Asset retirement costs		(365	)		2,151
Total costs incurred	$	14,636		$	132,427

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	December 31,
	2016			2015
	(in thousands)
Oil and natural gas:
Proved properties	$	4,262,155		$	4,231,836
Unproved properties		764,655			779,225
		5,026,810			5,011,061
Less accumulated depletion and amortization		(2,789,368	)		(1,596,165	)
	$	2,237,442		$	3,414,896

F-61

Results of Oil and Natural Gas Producing Activities

The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:

	Year Ended December 31,
	2016			2015
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	392,345		$	575,031
Gains (losses) on oil and natural gas derivatives		(15,781	)		29,175
		376,564			604,206
Production costs:
Lease operating expenses		185,056			245,155
Transportation expenses		41,619			52,160
Severance taxes, ad valorem taxes and California carbon allowances		24,982			70,591
		251,657			367,906
Other costs:
Depletion and amortization		169,605			241,019
Impairment of long-lived assets		1,030,588			853,810
(Gains) losses on sale of assets and other, net		(7	)		372
		1,200,186			1,095,201
Income tax expense (benefit)		116			(68	)
Results of operations	$	(1,075,395	)	$	(858,833	)

There is no federal tax provision included in the results above because the Company was not subject to federal income taxes during those periods. The income tax amount included in the results above relates to Texas margin tax expense. Limited liability companies are subject to Texas margin tax. See Note 10 for additional information about income taxes.

F-62

Proved Oil, Natural Gas and NGL Reserves

The proved reserves of oil and natural gas of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2016 and December 31, 2015, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the U.S., is shown below:

	Year Ended December 31, 2016
	Oil MBbls			NGL MBbls			Natural Gas MMcf			Total MBOE
Total proved reserves:
Beginning of year		93,892			16,953			387,848			175,487
Revisions of previous estimates		(31,350	)		(568	)		13,311			(29,701	)
Extensions, discoveries and other additions		1,797			—			178			1,827
Production		(8,463	)		(1,307	)		(28,577	)		(14,533	)
End of year		55,876			15,078			372,760			133,080
Proved developed reserves		55,422			15,078			372,760			132,626
Proved undeveloped reserves		454			—			—			454
Total proved reserves		55,876			15,078			372,760			133,080
	Year Ended December 31, 2015
	Oil MBbls			NGL MBbls			Natural Gas MMcf			Total MBOE
Total proved reserves:
Beginning of year:
Proved developed reserves		104,337			14,702			552,184			211,069
Proved undeveloped reserves		40,073			5,290			134,853			67,839
Total proved reserves		144,410			19,992			687,037			278,908
Revisions of previous estimates		(40,348	)		(2,012	)		(270,030	)		(87,365	)
Extensions, discoveries and other additions		793			34			4,693			1,610
Production		(10,963	)		(1,061	)		(33,852	)		(17,666	)
End of year		93,892			16,953			387,848			175,487
Proved developed reserves		93,892			16,953			387,848			175,487
Proved undeveloped reserves		—			—			—			—
Total proved reserves		93,892			16,953			387,848			175,487

The tables above include changes in estimated quantities of natural gas reserves shown in BOE using the ratio of six Mcf to one barrel.

Proved reserves decreased by approximately 42,407 MBOE to approximately 133,080 MBOE for the year ended December 31, 2016, from 175,487 MBOE for the year ended December 31, 2015. The year ended December 31, 2016, includes approximately 29,701 MBOE of negative revisions of previous estimates (22,729 MBOE due to asset performance and 6,972 due to lower commodity prices). In addition, extensions and discoveries, primarily from 23 productive wells drilled during the year, contributed approximately 1,827 MBOE to the increase in proved reserves.

Proved reserves decreased by approximately 103,421 MBOE to approximately 175,487 MBOE for the year ended December 31, 2015, from 278,908 MBOE for the year ended December 31, 2014. The year ended

F-63

December 31, 2015, includes approximately 87,365 MBOE of negative revisions of previous estimates (71,389 MBOE due to lower commodity prices, 15,067 MBOE due to uncertainty regarding the Company’s future commitment to capital and 10,733 MBOE due to the SEC five-year development limitation on PUDs, partially offset by 9,824 MBOE of positive revisions due to asset performance). In addition, extensions and discoveries, primarily from 196 productive wells drilled during the year, contributed approximately 1,610 MBOE to the increase in proved reserves.

As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved at December 31, 2015.

Standardized Measure of Discounted Future Net Cash Flows

Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 10 for additional information about income taxes.

	December 31,
	2016			2015
	(in thousands)
Future estimated revenues	$	3,131,758		$	5,483,899
Future estimated production costs		(1,893,608	)		(3,458,415	)
Future estimated development costs		(220,374	)		(332,311	)
Future net cash flows		1,017,776			1,693,173
10% annual discount for estimated timing of cash flows		(421,554	)		(697,801	)
Standardized measure of discounted future net cash flows	$	596,222		$	995,372
Representative NYMEX prices:(1)
Oil(Bbl)	$	42.64		$	50.16
Natural gas (MMBtu)	$	2.48		$	2.59

(1) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

F-64

The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:

	December 31,
	2016			2015
	(in thousands)
Standardized measure – beginning of year	$	995,372		$	4,330,377
Sales and transfers of oil, natural gas and NGL produced during the period		(140,688	)		(207,125	)
Changes in estimated future development costs		66,386			431,622
Net change in sales and transfer prices and production costs related to future production		(242,982	)		(3,203,620	)
Extensions, discoveries and improved recovery		21,610			20,345
Previously estimated development costs incurred during the period		—			67,529
Net change due to revisions in quantity estimates		(158,474	)		(544,334	)
Accretion of discount		99,537			433,038
Changes in production rates and other		(44,539	)		(332,460	)
Net decrease		(399,150	)		(3,335,005	)
Standardized measure – end of year	$	596,222		$	995,372

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

F-65

BERRY PETROLEUM COMPANY, LLC (DEBTOR-IN-POSSESSION)

SUPPLEMENTAL QUARTERLY DATA

(Unaudited)

The following discussion and analysis should be read in conjunction with the “Financial Statements” and “Notes to Financial Statements,” which are included in this prospectus in “Financial Statements and Supplementary Data.”

Quarterly Financial Data

	Quarters Ended
	March 31			June 30			September 30			December 31
	(in thousands)
2016:
Oil, natural gas and natural gas liquids sales	$	83,466		$	99,831		$	102,241		$	106,807
Electricity sales		4,211			5,118			8,244			5,631
Gains (losses) on oil and natural gas derivatives		508			1,026			108			(17,423	)
Total revenues and other		91,266			108,639			113,325			97,861
Total expenses(1)		1,196,393			33,868			111,600			118,207
(Gains) losses on sale of assets and other, net		(192	)		425			(87,915	)		(33,833	)
Reorganization items, net		—			49,086			(87,915	)		(33,833	)
Net income (loss)		(1,124,819	)		6,840			(98,438	)		(66,779	)
	Quarters Ended
	March 31			June 30			September 30			December 31
	(in thousands)
2015:
Oil, natural gas and natural gas liquids sales	$	156,586		$	173,381		$	140,252		$	104,812
Electricity sales		5,151			6,609			8,610			4,174
Gains (losses) on oil and natural gas derivatives		3,267			(4,474	)		27,664			2,718
Total revenues and other		169,281			177,890			79,307			115,176
Total expenses(1)		474,938			191,222			696,633			218,155
(Gains) losses on sale of assets and other, net		(4,473	)		(811	)		2,633			732
Net loss		(322,725	)		(28,832	)		(537,158	)		(126,462	)

(1) Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

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ANNEX A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this prospectus, which are commonly used in the oil and natural gas industry:

“API” gravity means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity scale developed by the American Petroleum Institute.

“basin” means a large area with a relatively thick accumulation of sedimentary rocks.

“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

“Bcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.

“Boe” means barrel of oil equivalent, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.

“Boe/d” means Boe per day.

“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.

“Btu” means one British thermal unit—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

“Completion” means the installation of permanent equipment for the production of oil or natural gas.

“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“Development drilling or Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.

“Diatomite” means a sedimentary rock composed primarily of siliceous, diatom shells.

“Differential” means an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.

“Enhanced oil recovery” means a technique for increasing the amount of oil that can be extracted from a field.

“EOR” means enhanced oil recovery.

“Estimated ultimate recovery” or “EUR” means the sum of reserves remaining as of a given date and cumulative production as of that date. As used in this prospectus, EUR includes only proved reserves and is based on our reserve estimates

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“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.

“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

“Formation” means a layer of rock which has distinct characteristics that differs from nearby rock

“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.

“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.

“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working interest.

“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.

“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.

“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability.

“Horizontal drilling” means a wellbore that is drilled laterally.

“ICE” means Intercontinental Exchange.

“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.

“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.

“IOR” means improved oil recovery.

“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

“MBbl” One thousand barrels of oil, condensate or NGLs.

“MBoe” One thousand barrels of oil equivalent.

“MBoe/d” MBoe per day.

“Mcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.

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“MMBbl” One million barrels of oil, condensate or NGLs.

“MMBoe” One million barrels of oil equivalent.

“MMBtu” One million Btus.

“MMcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.

“MMcf/d” means MMcf per day.

“MW” megawatt

“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.

“NGL” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

“NYMEX” means New York Mercantile Exchange.

“Oil” means crude oil or condensate.

“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

“PDNP” is an abbreviation for proved developed non-producing.

“PDP” is an abbreviation for proved developed producing.

“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.

“Play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations.

“Porosity” means the total pore volume per unit volume of rock.

“PPA” is an abbreviation for power purchase agreement.

“Production costs” means costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.

“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.

“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

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“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing equipment and operating methods.

“Proved reserves” means the estimated quantities of oil, gas and 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 estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty

“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.

“R/P Ratio” means reserves to production ratio, which indicates the number of years that current reserves would last if the rate of production did not change.

“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.

“Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.

“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related

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substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.

“SEC Pricing” means calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the twelve months ended on the given date.

“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.

“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Thickness” means the thickness of a layer or stratum of sedimentary rock measured perpendicular to its lateral extent, presuming deposition on a horizontal surface.

“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

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“Unproved reserves” means reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.

“Wellbore” means the hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.

“Workover” means maintenance on a producing well to restore or increase production.

“WTI” means West Texas Intermediate.

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Shares

Berry Petroleum Corporation

Common Stock

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below is a table of the registration fee for the Securities and Exchange Commission and estimates of all other expenses to be paid by the registrant in connection with the issuance and distribution of the securities described in the registration statement:

SEC registration fee	$	*
FINRA filing fee		*
listing fee		*
Printing fees and expenses		*
Accounting fees and expenses		*
Legal fees and expenses		*
Engineering fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*

* To be provided by amendment.

Item 14. Indemnification of Directors and Officers.

We are incorporated in Delaware. Under Section 145 of the DGCL, a Delaware corporation has the power, under specified circumstances, to indemnify its directors, officers, employees and agents in connection with actions, suits or proceedings brought against them by a third party or in the right of the corporation, by reason that they were or are such directors, officers, employees or agents, against expenses and liabilities incurred in any such action, suit or proceeding so long as they acted in good faith and in a manner that they reasonably believed to be in, or not opposed to, the best interests of such corporation, and with respect to any criminal action, that they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in the right of such corporation, however, indemnification is generally limited to attorneys’ fees and other expenses and is not available if such person is adjudged to be liable to such corporation unless the court determines that indemnification is appropriate. A Delaware corporation also has the power to purchase and maintain insurance for such persons.

Section 102(b)(7) of the DGCL provides that a certificate of incorporation may contain a provision eliminating or limiting the personal liability of a director to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director provided that such provisions may not eliminate or limit the liability of a director (i) for any breach of the director’s duty of loyalty to the corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 (relating to liability for unauthorized acquisitions or redemptions of, or dividends on, capital stock) of the DGCL, or (iv) for any transaction from which the director derived an improper personal benefit. Article 9 of our Amended and Restated Certificate of Incorporation limits its directors’ personal liability to the fullest extent permitted by the DGCL. Article 10 of our Amended and Restated Certificate of Incorporation provides that we will indemnify any director or officer who was or is a party or is threatened to be made a party to or is involved in any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (a “proceeding”), by reason of the fact that he or she is or was a director or officer of Berry Corp. or is or was serving at the request of Berry Corp. as a director, officer, manager, employee or agent of another corporation or of a limited liability company, partnership, joint venture, trust or other enterprise, except that we will indemnify any such person seeking indemnification in connection with a proceeding initiated by that person, only if that proceeding was authorized by the board of directors. The right to indemnification includes the right to be paid the expenses incurred in defending any such proceeding in advance of its final disposition.

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We have also entered into indemnification agreements with each of our directors and officers that provide contractual rights to indemnity and expense advancement and include related provisions meant to facilitate the indemnitees’ receipt of such benefits. Under these indemnification agreements, we must maintain directors and officers insurance. The terms of the indemnification agreements provide that we will indemnify the officers and directors against all losses that occur as a result of the indemnitee’s corporate status, including, without limitation, all liability arising out of the sole, contributory, comparative or other negligence, or active or passive wrongdoing of the indemnitee. Except as otherwise provided in the indemnification agreements, the only limitation that will exist upon our indemnification obligations pursuant to the agreements is that we are not obligated to make any payment to an indemnitee that is finally adjudged to be prohibited by applicable law. Under the indemnification agreements, we also agree to pay all expenses for which we may be jointly liable with an indemnitee and to waive any potential right of contribution we might otherwise have. Further, we agree to advance expenses to indemnitees in connection with proceedings brought as a result of the indemnitee’s corporate status.

The above discussion of our Amended and Restated Certificate of Incorporation, indemnification agreements with our officers and directors, and Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is qualified in its entirety by such Amended and Restated Certificate of Incorporation, indemnification agreements, and statutes.

Berry Corp. currently maintains an insurance policy which, within the limits and subject to the terms and conditions thereof, covers certain expenses and liabilities that may be incurred by directors and officers in connection with proceedings that may be brought against them as a result of an act or omission committed or suffered while acting as a director or officer.

Item 15. Recent Sales of Unregistered Securities.

On February 28, 2017, in connection with the emergence of Berry LLC from Chapter 11, we issued 32,920,000 shares of our common stock and 35,845,001 shares of Series A Preferred Stock pursuant to the Plan of Reorganization. 336,586 of the shares of Series A Preferred Stock were issued pursuant to an exemption from registration under Section 4(a)(2) of the Securities Act. The remaining shares of Series A Preferred Stock and all of the common stock were issued pursuant to an exemption from registration under Section 1145(a)(1) of the Bankruptcy Code.

On February 8, 2018, we completed the 2018 Notes Offering. The 2026 Notes were issued at a price of 100% of par, and the sale resulted in net proceeds (after deducting the Initial Purchasers’ discounts and commissions and estimated offering expenses and excluding accrued interest) to the Company of approximately $392 million. We used the net proceeds to repay borrowings under our RBL Facility and for general corporate purposes.

The 2026 Notes were issued and sold to the Initial Purchasers in a private placement exempt from the registration requirements of the Securities Act. The Initial Purchasers intend to resell the New Notes to qualified institutional buyers inside the United States in reliance on Rule 144A of the Securities Act and to persons outside the United States under Regulation S of the Securities Act.

Item 16. Exhibits.

Exhibit Number	Description
1.1*	Form of Underwriting Agreement
2.1	Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC, dated January 25, 2017

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Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation of Berry Petroleum Corporation
3.2	Amended and Restated Bylaws of Berry Petroleum Corporation
3.3	First Amendment to the Amended and Restated Bylaws of Berry Petroleum Corporation
3.4	Certificate of Designation of Series A Convertible Preferred Stock of Berry Petroleum Corporation
4.1	Form of Common Stock Certificate of Berry Petroleum Corporation
4.2	Form of Series A Convertible Preferred Stock Certificate of Berry Petroleum Corporation
4.3	Indenture dated as of February 8, 2018, among Berry Petroleum Company, LLC, Berry Petroleum Corporation and Wells Fargo Bank, N.A., as trustee
5.1*	Form of Opinion of Vinson & Elkins L.L.P.
10.1	Assignment Agreement, dated February 28, 2017, between Linn Acquisition Company, LLC and Berry Petroleum Corporation
10.2	Transition Services and Separation Agreement, dated February 28, 2017, by and among Berry Petroleum Company, LLC, Linn Energy, LLC and certain of its affiliates and subsidiaries
10.3	Stockholders Agreement, dated February 28, 2017, between Berry Petroleum Corporation and certain holders party thereto
10.4	Registration Rights Agreement, dated February 28, 2017, among Berry Petroleum Corporation and the holders party thereto
10.5†*	Executive Employment Agreement, dated March 1, 2017, between Berry Petroleum Corporation and Arthur T. Smith
10.6†*	Executive Employment Agreement, dated June 28, 2017, between Berry Petroleum Corporation and Cary Baetz
10.7†*	Executive Employment Agreement, dated June 28, 2017, between Berry Petroleum Corporation and Gary A. Grove
10.8†*	Berry Petroleum Corporation 2017 Omnibus Incentive Plan
10.9†*	Berry Petroleum Corporation Form of Nonqualified Stock Option Grant Certificate
10.10†*	Berry Petroleum Corporation Form of Restricted Stock Unit Grant Certificate
10.11†*	Berry Petroleum Corporation Form of Director Restricted Stock Unit Grant Certificate
10.12*	Form of Indemnification Agreement
10.13	Credit Agreement, dated February 28, 2017, by and among Berry Petroleum Company, LLC, as borrower, Berry Petroleum Corporation, as guarantor, Wells Fargo Bank, N.A., as administrative agent, and certain lenders
10.14	Guaranty Agreement, dated February 28, 2017, among Berry Petroleum Company, LLC and Berry Petroleum Corporation, as guarantors, and Wells Fargo Bank, N.A., as administrative agent
10.15	Pledge Agreement, dated February 28, 2017, among Berry Petroleum Company, LLC and Berry Petroleum Corporation, as pledgors, and Wells Fargo Bank, N.A., as administrative agent
10.16	Security Agreement, dated February 28, 2017, among Berry Petroleum Company, LLC and Berry Petroleum Corporation, as debtors, and Wells Fargo Bank, N.A., as administrative agent

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Exhibit Number	Description
10.17	Credit Agreement, dated July 31, 2017, by and among Berry Petroleum Company, LLC, as borrower, Berry Petroleum Corporation, as guarantor, Wells Fargo Bank, N.A., as administrative agent and issuing lender, and certain lenders
10.18	Guaranty Agreement, dated July 31, 2017, among Berry Petroleum Company, LLC and Berry Petroleum Corporation, as guarantors, and Wells Fargo Bank, N.A., as administrative agent
10.19	Pledge Agreement, dated July 31, 2017, among Berry Petroleum Company, LLC and Berry Petroleum Corporation, as pledgors, and Wells Fargo Bank, N.A., as administrative agent
10.20	Security Agreement, dated July 31, 2017, among Berry Petroleum Company, LLC and Berry Petroleum Corporation, as debtors, and Wells Fargo Bank, N.A., as administrative agent
21.1	List of Subsidiaries of Berry Petroleum Corporation
23.1*	Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1)
23.2*	Consent of KPMG LLP
23.3*	Consent of DeGolyer and MacNaughton
24.1*	Powers of Attorney of the Directors and Officers of the Registrant (included on signature pages of this Registration Statement)
99.1	Report as of November 30, 2017 of DeGolyer and MacNaughton

(*) To be filed by amendment.

(†) Indicates a management contract or compensatory plan or arrangement.

Item 17. Undertakings.

The undersigned registrant hereby undertakes:

(a) to provide to the underwriter at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter to permit prompt deliver to each purchaser;

(b) to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) to include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(ii) to reflect in the prospectus any facts or events arising after the effective date of this registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in this registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

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(iii) to include any material information with respect to the plan of distribution not previously disclosed in this registration statement or any material change to such information in this registration statement;

(c) that, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof;

(d) to remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering;

(e) that, for purposes of determining liability under the Securities Act of 1933 to any purchaser:

(i) If the registrant is relying on Rule 430B:

(A) Each prospectus filed by the registrant pursuant to Rule 424(b)(3) shall be deemed to be part of this registration statement as of the date the filed prospectus was deemed part of and included in this registration statement; and

(B) each prospectus required to be filed pursuant to Rule 424(b)(2), (b)(5), or (b)(7) as part of a registration statement in reliance on Rule 430B relating to an offering made pursuant to Rule 415(a)(1)(i), (vii), or (x) for the purpose of providing the information required by section 10(a) of the Securities Act of 1933 shall be deemed to be part of and included in the registration statement as of the earlier of the date such form of prospectus is first used after effectiveness or the date of the first contract of sale of securities in the offering described in the prospectus. As provided in Rule 430B, for liability purposes of the issuer and any person that is at that date an underwriter, such date shall be deemed to be a new effective date of the registration statement relating to the securities in the registration statement to which that prospectus relates, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such effective date, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such effective date; or

(ii) if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant’s annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Bakersfield, State of California, on             , 2018.

Berry Petroleum Corporation
By:
Name:	Arthur T. Smith
Title:	President and Chief Executive Officer

Each person whose signature appears below hereby constitutes and appoints                  and                 , and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution for him in any and all capacities, to sign any or all amendments or post-effective amendments to this Registration Statement, or any Registration Statement for the same offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with exhibits hereto and other documents in connection therewith or in connection with the registration of the securities under the Securities Act of 1933, as amended, with the Securities and Exchange Commission, granting unto such attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary in connection with such matters and hereby ratifying and confirming all that such attorneys-in-fact and agents or his substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on             , 2018.

Signature	Title
	President and Chief Executive Officer, and Director
Arthur T. Smith	(Principal Executive Officer)
	Executive Vice President and Chief Financial
Cary Baetz	Officer, and Director (Principal Financial and Accounting Officer)
Eugene J. Voiland	Director
Brent S. Buckley	Director
Kaj Vazales	Director

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