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 as noted or as 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 B: Glossary of Oil and Natural Gas Terms.”

Our Company

We are a California-based independent upstream energy company engaged primarily in the development and production of conventional oil reserves located in the western United States. Our long-lived, predictable and high margin asset base is uniquely positioned to support our objectives of generating top-tier corporate-level returns and positive free cash flow through commodity price cycles. We believe that executing our strategy across our low-declining production base and extensive inventory of identified drilling locations will result in long-term, capital efficient production growth as well as the ability to return excess free cash flow to stockholders.

We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin of California and the Uinta basin of Utah, and, to a lesser extent, the low geologic risk natural gas resource play in the Piceance basin in Colorado. In the aggregate, the Company’s assets are characterized by:

California is and has been one of the most productive oil and natural gas regions in the world. Our asset base is concentrated in the oil-rich San Joaquin basin in California, which has more than 100 years of production history and substantial remaining oil in place. As a result of these attributes, we have a strong understanding of many of the basin’s geologic and reservoir characteristics, leading to predictable, repeatable, low-risk development opportunities.

In California, we focus on conventional, shallow reservoirs, the drilling and completion of which are relatively low-cost in contrast to modern unconventional resource plays. Our decades-old proven completion

techniques in these reservoirs include steamflood and low-volume fracture stimulation. For example, we estimate the cost of Proved Undeveloped Reserves (“PUD”) wells drilled and completed in California will average less than $450,000 per well. In contrast, we estimate the cost of PUD wells drilled and completed in the Piceance basin will average $1.8 million per well. Using SEC Pricing as of December 31, 2017, there were approximately 80 gross PUD locations associated with projects in the Piceance basin. Subsequent to year end, as a result of increasingly negative local gas pricing differentials, we revised our current development plan to exclude these Piceance locations.

We also own assets in the Uinta basin in Utah, a stacked, multi-bench, light-oil-prone play with significant undeveloped resources where we have high operational control and additional behind pipe potential and in the East Texas basin, an extensive over-pressured natural gas cell, as well as in the Piceance basin in Colorado, a prolific low geologic risk natural gas play where we produce from a conventional, tight sandstone reservoir using proven slick water fracture stimulation techniques to increase recoveries.

We are led by an executive leadership team with over 100 years of combined energy industry experience and an average of over 25 years in the sector. Our management will leverage their collective experience, which spans domestic and international basins as well as a variety of reservoir recovery types, to enhance existing production, improve drilling and completion techniques, control costs and maximize the ultimate recovery of hydrocarbons from our assets with the ultimate objective of increasing stockholder value.

Using SEC Pricing as of December 31, 2017, we had estimated total proved reserves of 141,384 MBoe. For the three months ended March 31, 2018, we had average production of approximately 26.2 MBoe/d, of which approximately 81% was oil. In California, our average production for the three months ended March 31, 2018 was 18.8 MBoe/d, of which approximately 100% was oil.

The Berry Advantage

We believe that our combination of low production decline rates, high margin oil-weighted production, attractive development opportunities and a stable cost environment differentiates us from our competitors and provides for low-breakeven commodity prices and an ability to generate top-tier corporate level returns, positive levered free cash flow and capital-efficient growth through commodity price cycles.

Our Low Declining Production Base

Our reserves are generally long-lived and characterized by relatively low production decline rates, affording us significant capital flexibility and an ability to efficiently hedge material quantities of future expected production. For example, our PDP reserves have an estimated compound annual decline rate of approximately 13% between 2018 and 2022 based on total PDP reserves as of December 31, 2017 as reflected in our SEC reserve report, which is attached as Annex A. Our SEC reserve report is based on the estimated individual well production profiles used to determine our PDP reserves. Based on the assumptions underlying our PUD estimates, we estimate that the annual capital budget required to keep production volumes consistent each year over the next three years is approximately $110 million.

Our Oil-Weighted, High Margin Production

Our highly oil-weighted production combined with a Brent-influenced California pricing dynamic and stable cost structures has resulted, and is expected to continue to result, in strong operating margins. As of December 31, 2017, our California PUD reserves were 100% oil.

Our Attractive Development Opportunities

Our estimated development costs associated with our PUD reserves are $8.89 per Boe on a total company basis and $10.95 per Boe in California. We believe that our estimated development costs, when combined with our operating costs, commodity mix and price realizations, present attractive breakeven economics for our development opportunities.

We expect our identified drilling locations to generate attractive rates of return. The following table presents our expected average single-well rates of return on drilling opportunities associated with our California PUD reserves based on the assumptions used in preparing our December 31, 2017 SEC reserve report, including pricing and cost assumptions, which can be found under “Primary Economic Assumptions” on page 6 of our reserve report. Using SEC Pricing as of December 31, 2017, there were approximately 23 MMBoe of PUDs associated with projects in the Piceance basin. Subsequent to year end, as a result of increasingly negative local gas pricing differentials, we revised our current development plan to exclude development in the Piceance basin. As a result, information with respect to our Colorado PUDs as of December 31, 2017 has been omitted from the table below. The table also includes a commodity price sensitivity scenario, which is based on Strip Pricing as of May 31, 2018.

Our Stable California Operating and Development Cost Environment

The operating and development cost structures of our conventional California asset base are inherently stable and predictable. Our California focus largely insulates us from the cost inflation pressures experienced by our peers who operate primarily in unconventional plays. This is the result of our established infrastructure, low-intensity service requirements and lack of dependence on inventory-constrained and often highly specialized equipment. In addition, the majority of our California assets reside in the shallow steam-flood fields of the San Joaquin basin, which are lower cost to develop compared to the water flood fields of the Los Angeles and Ventura basins.

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 and in the East Texas basin, an extensive over-pressured natural gas cell, as well as in the Piceance basin in Colorado, a prolific natural gas play with low geologic risk.

Using SEC Pricing as of December 31, 2017, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our proved reserves were approximately $1.0 billion and $1.1 billion, respectively. Using Strip Pricing as of May 31, 2018, the PV-10 of our proved reserves was approximately $1.9 billion. PV-10 is a financial measure that is not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—Summary Reserves and Operating Data—PV-10.”

The charts below summarize certain characteristics of our proved reserves and PV-10 of proved reserves using SEC Pricing as of December 31, 2017 and Strip Pricing as of May 31, 2018 (as described in the tables below and in “—Summary Reserves and Operating Data”):

The tables below summarize our proved reserves and PV-10 by category using SEC Pricing as of December 31, 2017 and Strip Pricing as of May 31, 2018:

The table below summarizes our average net daily production by basin for the three months ended March 31, 2018:

Our Development Inventory

We have an extensive inventory of low-risk, high-return development opportunities. As of March 31, 2018, we identified 3,397 gross drilling locations that we anticipate drilling over the next 5 to 10 years, which we refer to as our “Tier 1” locations, and 3,656 additional gross drilling locations that are currently under review. For a discussion of how we identify drilling locations, please see “Business—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 operations as of March 31, 2018:

Additionally, our California assets are primarily focused on the Hill Diatomite, Thermal Diatomite and Thermal Sandstones development areas. As set forth in the table below, as of March 31, 2018, we identified 3,397 Tier 1 gross drilling locations and 3,656 additional gross drilling locations that are currently under review associated with these assets. Our drilling inventory as of March 31, 2018 does not include 250 gross (250 net) locations associated with the Chevron North Midway-Sunset acquisition, which was completed in April 2018.

Other Assets

We produce oil from heavy crude reservoirs using steam to heat the oil so that it will flow. To assist in this development, we own and operate five natural gas cogeneration plants that produce steam. These plants supply approximately 23% of our steam needs and 82% of our field electricity needs in California at a discount to electricity market prices. To further offset our costs, we currently 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 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 compression facilities we operate. Approximately 90% 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 Competitive Strengths

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

Our Business Strategy

The principal elements of our business strategy include the following:

Our Capital Budget

Following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities, we increased our pace of development and have continued to do so in 2018. Our 2018 anticipated capital expenditure budget of approximately $140 to $160 million represents an increase of approximately 107% over our 2017 capital expenditures, including the successor and predecessor periods, of approximately $73 million. Our 2019 anticipated capital expenditure budget is approximately $210 to $230 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 and 2019 capital programs exclusively with our levered free cash flow. We expect to:

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, and we target covering our operating expenses and fixed charges two years out. 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 May 31, 2018.

Hedge Volumes in MMBbls (MBbl/d)

Recent Developments

Chevron North Midway-Sunset Acquisition

In April 2018, we acquired from Linn Energy Holdings, LLC, a wholly owned subsidiary of Linn Energy (“Linn Holdings”), two leases on an aggregate of 214 acres and a lease option on 490 acres (the “Chevron North Midway-Sunset Acquisition”) of land owned by Chevron U.S.A. in the north Midway-Sunset field immediately adjacent to assets we currently operate. We assumed a drilling commitment for the 214 acres of approximately $34.5 million to drill 115 wells, of which none have been drilled, on or before April 1, 2020, which has been extended to April 1, 2022, and would assume an additional 40 well drilling commitment if we exercise our option on the 490 acres. We paid no other consideration for the acquisition. Our drilling commitment will be tolled for a month for each consecutive 30-day period for which the posted price of WTI is less than $45 per barrel. Our 2018 anticipated capital expenditure budget does not currently include funding for drilling wells against the

assumed drilling commitment, but we have designated funds for drilling appraisal wells to determine whether to exercise the option. This transaction is consistent with our business strategy to investigate areas beyond our known productive areas. See “—Our Business Strategy—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.”

Senior Unsecured Notes Offering

In February 2018, we closed the offering of $400 million in aggregate principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the issuance of the 2026 Notes to repay borrowings under the RBL Facility and used the remainder for general corporate purposes.

Preferred Stock Conversion

In connection with this offering, we will amend the Certificate of Designation (the “Series A Certificate of Designation”) of our Series A Convertible Preferred Stock, par value $0.001 per share (the “Series A Preferred Stock”), to provide for the automatic conversion of all outstanding shares of Series A Preferred Stock. Pursuant to the amendment, each outstanding share of Series A Preferred Stock will be automatically converted into (i) 1.05 shares of common stock and (ii) the right to receive $1.75, minus the amount of any cash dividend paid by the Company on such share of Series A Preferred Stock in respect of any period commencing on or after April 1, 2018 (the “Preferred Stock Conversion”). We will use a portion of the proceeds from this offering to fund the cash payable to holders of Series A Preferred Stock in connection with the Preferred Stock Conversion. See “Use of Proceeds.”

Selected Preliminary Operating and Financial Second Quarter Results

Our unaudited condensed consolidated financial statements as of and for the three months ended June 30, 2018 are not yet available. The following estimates are based on our preliminary operating and financial results as of and for the three months ended June 30, 2018 and, as of the date of this prospectus, have not been finalized. These preliminary estimates are derived from our internal records and are based on the most current information available to management. We have prepared these estimates on a basis materially consistent with our historical financial results and in good faith based on our internal reporting as of and for the three months ended June 30, 2018. However, the preliminary financial estimates are not reviewed and are unaudited, and our normal reporting processes with respect to the following preliminary operational and financial results have not been fully completed. During the course of our review process on our operating and financial results as of and for the three months ended June 30, 2018, we could identify items that would require us to make adjustments and could affect our final results. Any such adjustments could be material. Please read “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Cautionary Note Regarding Forward-Looking Statements” for additional information regarding factors that could result in differences between the preliminary operating and financial results that are presented below and the actual results as of and for the three months ended June 30, 2018.

This summary is not intended to be a comprehensive statement of our unaudited financial results for this period. The results of operations for an interim period, including the summary preliminary financial results provided below, may not give a true indication of the results to be expected for a full year or any future period. In addition, the preliminary financial results set forth below should not be viewed as a substitute for full financial statements prepared in accordance with GAAP. Our consolidated financial statements and related notes as of and

for the three months ended June 30, 2018 are not expected to be filed with the SEC until after this offering is completed.

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 30 for an explanation of these risks before investing in our common stock and “Cautionary Note Regarding Forward-Looking Statements” on page 50 of this prospectus. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities:

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 small mining operation during the Alaskan gold rush, Mr. Berry returned to California and continued his success with oil exploration and production, founding, in the early 1900s, the business that we would later inherit. Our corporate 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 in exchange for LinnCo shares and the assumption of 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 and operational positions from that of Berry LLC while it was owned by the Linn Entities. These improvements included:

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.

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:

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

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. For a description of the qualifications and other requirements applicable to emerging growth companies and certain elections that we have made due to our status as an emerging growth company, see “Risk Factors—Risks Related to the Offering and Our Capital Stock—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.”

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.

The Offering

Because of the conflicts of interest, this offering is being conducted in accordance with FINRA Rule 5121, which requires, among other

things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus.

In accordance with this rule,                  has assumed the responsibilities of acting as a qualified independent underwriter.                  will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering.                     , Wells Fargo Securities, LLC and BMO Capital Markets Corp. will not confirm sales of the shares to any account over which it exercises discretionary authority without the prior written approval of the customer. For more information, please see “Underwriting (Conflicts of Interest)—Conflicts of Interest.”

The number of shares of common stock that will be outstanding after this offering excludes shares of common stock reserved and available for issuance under the Berry Petroleum Corporation 2017 Omnibus Incentive Plan, as amended and restated (our “Restated Incentive Plan”). As of June 27, 2018, 9,832,111 of the 10,000,000 shares of common stock originally authorized for issuance under the Restated Incentive Plan may be issued in the future pursuant to awards under the Restated Incentive Plan, of which 1,477,998 shares are currently subject to outstanding awards. 167,889 shares of common stock have previously been issued pursuant to awards and are included in the number of shares of common stock that will be outstanding after this offering.

The number of shares of common stock that will be outstanding after this offering also excludes 7,080,000 shares reserved for issuance in connection with settlement of bankruptcy claims as discussed in “Shares Eligible For Future Sale—Plan of Reorganization.” To the extent that holders of unsecured claims elected to receive cash rather than common stock in settlement of their allowed claims, the stock they would have received from the reserved amount will be retained by us as treasury stock under the Plan. While we do not yet know the final amount of shares that we will issue to third parties with respect to the unsecured claims, we have entered into settlement agreements that have materially reduced the potential shares to be issued from the reserved amount. Based on the settlements we have finalized to date, we estimate that we will distribute less than              million shares, and we are currently pursuing additional settlements that would further reduce the number of shares that would ultimately be issued in settlement of claims.

Summary Historical and Pro Forma Financial Information

The following table shows the summary historical financial information, for the periods and as of the dates indicated, of our predecessor company (Berry LLC) and successor company (Berry Corp.). The summary historical financial information as of and for the year ended December 31, 2016 is derived from the audited historical financial statements of Berry LLC included elsewhere in this prospectus. The summary historical financial information as of and for the two months ended February 28, 2017 is derived from audited financial statements of Berry LLC included elsewhere in this prospectus. The summary historical financial information for the ten months ended December 31, 2017 is derived from audited consolidated financial statements of Berry Corp. included elsewhere in this prospectus. The summary historical financial information as of and for the one month ended March 31, 2017 and as of and for the three months ended March 31, 2018 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 Berry LLC’s historical 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 are not comparable to our 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, 2017 is derived from the audited historical financial statements of Berry LLC and Berry Corp. included elsewhere in this prospectus. The summary unaudited pro forma financial information for the three months ended March 31, 2018 is derived from the unaudited historical financial statements of Berry Corp. included elsewhere in this prospectus.

The summary unaudited pro forma financial information for the year ended December 31, 2017 has been prepared to give pro forma effect to (i) the Plan and related transactions and fresh-start accounting, (ii) our sale of an approximately 78% non-operated working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle on July 30, 2017 (the “Hugoton Disposition”) and (iii) the Preferred Stock Conversion and this offering, including the application of net proceeds from this offering, as if each had been completed as of January 1, 2017. The summary unaudited pro forma financial information does not give effect to the acquisition we made of 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”) 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, the Hugoton Disposition, the Preferred Stock Conversion or this offering, including the application of net proceeds from this offering, 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.

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.

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 or paid for scheduled 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 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.

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.

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 and stock compensation expense is non-cash in nature. 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.

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 see “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 using SEC Pricing as of December 31, 2017 and Strip Pricing as of May 31, 2018. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton. The SEC Pricing reserve estimates were prepared in accordance with current SEC rules and regulations regarding oil, natural gas and NGL reserve reporting and Strip Pricing data was prepared using closing month futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX Henry Hub for natural gas on May 31, 2018. Reserves are stated net of applicable royalties.

Our Strip Pricing oil, natural gas and NGL reserves were determined using index prices for natural gas and oil, respectively, as of May 31, 2018 without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our Strip Pricing reserves were $74.59 per Bbl for oil and NGLs for 2018, $72.98 for 2019, $69.15 for 2020 and $66.49 for 2021 thereafter, on the ICE (Brent), and $2.94 per Mcf for natural gas for 2018, $2.75 for 2019, $2.68 for 2020 and $2.66 for 2021 thereafter, on the NYMEX Henry Hub. NGL pricing used in determining our Strip Pricing reserves was approximately 36% of future crude oil prices. Also, we have taken into account pricing differentials reflective of the current market environment.

We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. Strip Pricing futures prices are not necessarily an accurate projection of future oil and gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves.

The decrease in reserve volumes using Strip Pricing as opposed to SEC Pricing is primarily the result of lower realized gas prices in Colorado using Strip Pricing as of May 31, 2018.

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.

The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows using SEC Pricing at December 31, 2017 (in millions):

GAAP does not prescribe any corresponding measure for PV-10 of reserves as of an interim date or on any basis other than SEC prices. As a result, it is not practicable for us to reconcile PV-10 using Strip Pricing as of May 31, 2018 to GAAP standardized measure.

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 year ended December 31, 2016, the two months ended

February 28, 2017, the one month ended March 31, 2017, the ten months ended December 31, 2017 and the three months ended March 31, 2018 and (ii) on a pro forma basis for the year ended December 31, 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, 2017, 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.”

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