DRS/A 1 filename1.htm DRS/A
Table of Contents

As confidentially submitted to the Securities and Exchange Commission on May 2, 2018

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Confidential Draft Submission No. 2

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

 

Gerald M. Spedale

Gibson, Dunn & Crutcher LLP

811 Main Street, Suite 3000

Houston, Texas 77002-6117

(346) 718-6600

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.

 

 

 


Table of Contents

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

 

LOGO

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 26 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 (Conflicts of Interest)” beginning on page 167 of this prospectus for additional information regarding underwriting compensation.

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

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

 

Goldman Sachs & Co. LLC   Wells Fargo Securities

 

 

The date of this prospectus is                     , 2018


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1  

RISK FACTORS

     26  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     48  

USE OF PROCEEDS

     50  

DIVIDEND POLICY

     51  

CAPITALIZATION

     52  

DILUTION

     53  

SELECTED HISTORICAL FINANCIAL DATA

     55  

PRO FORMA FINANCIAL DATA

     57  

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

     63  

BUSINESS

     94  

MANAGEMENT

     137  

EXECUTIVE COMPENSATION

     142  

PRINCIPAL AND SELLING STOCKHOLDERS

     149  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     151  

DESCRIPTION OF CAPITAL STOCK

     153  

SHARES ELIGIBLE FOR FUTURE SALE

     159  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

     162  

UNDERWRITING (CONFLICTS OF INTEREST)

     167  

LEGAL MATTERS

     173  

EXPERTS

     173  

WHERE YOU CAN FIND MORE INFORMATION

     173  

INDEX TO FINANCIAL STATEMENTS

     F-1  

ANNEX A: RESERVE LETTER

     A-1  

ANNEX B: GLOSSARY OF OIL AND NATURAL GAS TERMS

     B-1  

 

 

We, the selling stockholders and the underwriters have not authorized anyone to provide you with information different from that contained in this prospectus or any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. 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


Table of Contents

BASIS OF PRESENTATION

In 2013, LINN Energy, LLC (“LINN Energy”) and LinnCo, LLC (“LinnCo” and, together with LINN Energy, the “Linn Entities”) acquired Berry Petroleum Company LLC (“Berry LLC”) in exchange for LinnCo shares and the assumption of 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 Petroleum Corporation (“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 is not comparable to information about our performance or financial condition after the Effective Date.

The financial information and certain other information presented in this prospectus have 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.

 

ii


Table of Contents

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.

 

 

iii


Table of Contents

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 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. 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:

 

    high oil content, which makes up approximately 79% of our production;

 

    favorable Brent-influenced crude oil pricing dynamics;

 

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

 

    stable and predictable development and production cost structures;

 

                     years of low-risk identified development drilling opportunities with attractive full-cycle economics; and

 

    potential in-basin strategic opportunities to expand our existing inventory with new locations of substantially similar geology and economics.

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



 

1


Table of Contents

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 cyclic or continuous steam injection (“steamflood”) and low-volume fracture stimulation. For example, we estimate the cost for PUD wells drilled and completed in California will average less than $450,000 per well.

We also maintain 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.

As of December 31, 2017, we had estimated total proved reserves of 141,385 MBoe, of which approximately 66% were located in California and 57% were proved developed producing reserves. For the three months ended December 31, 2017, we had average production of approximately 27.9 MBoe/d, of which approximately 79% 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 reserve report, which is attached as Annex A. Our 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 in 2018 approximately $70 million to $80 million of our capital budget will be sufficient to maintain production volumes consistent with those achieved in 2017.



 

2


Table of Contents

Our Oil-Weighted, High Margin Production

Our high oil content combined with a Brent-influenced California pricing dynamic and attractive cost structure has resulted in strong operating margins.

We expect our PUD reserves to have lower operating expenses per Boe than our PDP reserves due to the higher rates of production associated with new wells compared to existing producing wells (which have been producing for an average of 11 years). The lower expected operating expenses of our PUDs also support attractive breakeven commodity prices all-in (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 average operating expenses per Boe over the next five years as provided to our reserve engineers in connection with the preparation of our December 31, 2017 reserve report.

PUD / PDP Operating Expenses (Avg. for 2018-2022)($/Boe)(1)(2)

 

LOGO

 

(1) Expected operating expenses, as estimated by our management and provided to our reserve engineers in connection with the preparation of our reserve report as of December 31, 2017, associated with (i) our PUDs as of December 31, 2017 are $11.1 million, $37.4 million, $61.8 million, $64.1 million and $60.1 million for 2018, 2019, 2020, 2021 and 2022, respectively, and (ii) our PDP reserves as of December 31, 2017 are $161.9 million, $144.0 million, $128.3 million, $114.0 million and $103.8 million for 2018, 2019, 2020, 2021 and 2022, respectively.
(2) Expected aggregate production associated with (i) our PUDs as of December 31, 2017 are 689,519 Boe, 3,075,502 Boe, 5,001,175 Boe, 5,527,523 Boe and 5,050,158 Boe for 2018, 2019, 2020, 2021 and 2022, respectively, and (ii) our PDP reserves as of December 31, 2017 are 9,350,473 Boe, 8,006,566 Boe, 6,944,450 Boe, 6,050,161 Boe and 5,352,475 Boe for 2018, 2019, 2020, 2021 and 2022, respectively. Our expected PUD production over the next five years reflects the aggregation of the expected individual production profiles of each of our 790 gross (786 net) PUD drilling locations as of December 31, 2017 over the next five years based on each location’s expected completion date and our five-year development plan. Our expected PDP production over the next five years reflects the aggregation of the expected individual production profiles of each of our producing wells as of December 31, 2017 over the next five years.

Operating expenses include lease operating expenses, electricity generation expenses, transportation expenses and marketing expenses, net of electricity sales and marketing revenue. Our



 

3


Table of Contents

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 further 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.”

Our Attractive Development Opportunities

We expect our identified drilling locations to generate attractive rates of return. For example, we expect the single-well rates of returns on our drilling opportunities associated with our PUD reserves to average approximately 45%, based on the assumptions used in preparing our December 31, 2017 reserve report, including pricing and cost assumptions, which can be found under “Primary Economic Assumptions” on page 6 of our reserve report.

Our estimated development costs associated with our PUD reserves are $8.89 per Boe. When combined with our anticipated PUD operating expenses for the next five years of $12.12 per Boe, we believe our identified development opportunities present attractive break-even economics.

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 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.

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. 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.”



 

4


Table of Contents

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

 

1P Reserves by Category (141 MMBoe)    1P Reserves by Commodity (141 MMBoe)
LOGO    LOGO
1P Reserves by Area (141 MMBoe)    1P PV-10 by Area ($1.1 billion)
        LOGO    LOGO     

The table below summarizes our proved reserves and PV-10 by category as of December 31, 2017:

 

     Oil
(MMBbl)
     Natural
Gas (Bcf)
     NGLs
(MMBbl)
     Total
(MMBoe)
     % of
Proved
     % Proved
Developed
     Capex(2)
($MM)
     PV-10(3)
($MM)
 
PDP(1)      63        100        1        81        57        93      $ 50      $ 762  
PDNP(1)      6        —          —          6        4        7        10        89  
PUDs(1)      32        137        —          55        39        —          488        262  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
Total(1)      101        237        1        141        100        100      $ 548      $ 1,114  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(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 $54.42 per Bbl ICE (Brent) for oil and NGLs and $2.98 per MMBtu NYMEX Henry Hub for natural gas at December 31, 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 December 31, 2017.
(3) PV-10 is a financial measure that is not calculated in accordance with 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.” PV-10 does not give effect to derivatives transactions.


 

5


Table of Contents

The table below summarizes our average net daily production by basin for the three months ended December 31, 2017:

 

     Average Net Daily Production for
the Three Months Ended

December 31, 2017
 
     (MBoe/d)      Oil (%)  

California

     19.5        100

Uinta basin

     5.3        48

Piceance basin

     2.2        2

East Texas basin

     0.9        —    
  

 

 

    

Total

     27.9        79
  

 

 

    

Our Development Inventory

We have an extensive inventory of low-risk, high-return development opportunities. In addition to our approximately 790 gross (786 net) identified drilling locations associated with proved undeveloped reserves as of December 31, 2017, we also have identified approximately 1,300 gross (1,300 net) additional drilling locations with economics that management believes are similar to those of our proved undeveloped locations. Further, we have identified an additional 3,800 gross (3,500 net) drilling locations, with economics 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 acreage, identified drilling locations and producing wells as of December 31, 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.


 

6


Table of Contents
(3) Our total identified drilling locations include approximately 790 gross (786 net) locations associated with PUDs as of December 31, 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 December 2017.

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 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 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 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 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. 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 structure and low-risk developmental drilling opportunities with predictable production profiles. The nature of our assets provides us with 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 proved undeveloped reserves are projected to average single-well rates of return of approximately 45%, based on the assumptions used in preparing our December 31, 2017 reserve report, including pricing and cost assumptions, which can be found under “Primary Economic Assumptions” on page 6 of our reserve report. We also have identified approximately 1,300 gross (1,300 net) additional drilling locations with economics that management believes are



 

7


Table of Contents
 

similar to those of our proved undeveloped locations and another 3,800 additional identified drilling locations that are currently under review.

 

    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.

 

    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 levered free cash flows as well as the value of our production and reserves. In doing so, we 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.

 

    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. We expect our operations to continue to generate sufficient levered free cash flow at current commodity prices to fund maintenance operations and growth. Also, unlike our peers who operate primarily in unconventional plays, our assets generally do not necessitate inventory-constrained and highly specialized equipment, which provides us relative insulation from cost inflation pressures. Our high degree of operational control and relatively stable cost environment provide us significant visibility and understanding of our expected cash flows.

 

    Conservative balance sheet leverage with ample liquidity and minimal contractual obligations. In February 2018, we closed a private offering (the “2018 Notes Offering”) of $400 million in aggregate principal amount of 7.00% 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. After giving effect to our sale of common stock in this offering, we expect to have approximately $             million of available liquidity, defined as cash on hand plus availability under the $1.5 billion reserve based lending facility we entered into on July 31, 2017 (as amended, the “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.


 

8


Table of Contents

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 levered free 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 proppantless slick water fracture stimulation techniques. In addition, we intend to take advantage of underdevelopment in basins where we operate by expanding our geologic investigation of deeper reservoirs on our acreage and adjacent acreage below existing producing reservoirs. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs.

 

    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.

 

    Return excess free cash flow to stockholders. Our objective is to implement a disciplined and returns-focused approach to capital allocation in order to generate excess free cash flow. We intend to return portions of that excess free cash flow to stockholders on a quarterly basis. For a discussion of our dividend policy, please see “Dividend Policy.”

 

    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. We will review our hedging program continuously as conditions change.


 

9


Table of Contents

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 92% over our 2017 capital expenditures, including the successor and predecessor periods, of approximately $73 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 exclusively 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 drilling opportunities in Colorado and Utah 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 consistent 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.



 

10


Table of Contents

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 March 31, 2018.

Hedge Volumes in MMBbls (MBbl/d)

 

LOGO

 

(1) Calculations based on 275 days as of March 31, 2018.

Recent Developments

Chevron North Midway-Sunset Acquisition

In April 2018, we acquired two leases and a lease option on approximately 700 acres (the “Chevron North Midway-Sunset Acquisition”) of land in the north Midway-Sunset field immediately adjacent to assets we currently operate. We assumed a drilling commitment of approximately $34.5 million over a 5-year term and would assume a further commitment if we exercise our option. 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. 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 2018 Notes Offering of $400 million in aggregate principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $392 million after



 

11


Table of Contents

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 used 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 26 for an explanation of these risks before investing in our common stock and “Cautionary Note Regarding Forward-Looking Statements” on page 48 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, including regulatory and permitting 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.

 

    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 to produce steam for our operations. Viable contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.

 

    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.


 

12


Table of Contents
    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.

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:

 

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

 

    a completely new and experienced management team intently focused on operational excellence and conservative financial risk management;

 

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

 

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

 

    $335 million of new capital in exchange for preferred equity.

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.



 

13


Table of Contents

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.

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.”



 

14


Table of Contents

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.



 

15


Table of Contents

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 for general corporate purposes. Please see “Use of Proceeds.”

Conflicts of Interest

  Certain investment funds affiliated with Goldman Sachs & Co. LLC, an underwriter in this offering, own in excess of 10% of our issued and outstanding common and preferred stock. Under the Rules of the Financial Industry Regulatory Authority, Inc. (“FINRA”), Goldman Sachs & Co. LLC is deemed to have a conflict of interest with us, and accordingly, this offering is being made in compliance with the requirements of Rule 5121 of FINRA. In accordance with this rule,              has assumed the responsibilities of acting as a qualified independent underwriter. In its role as qualified independent underwriter,              has participated in due diligence and the preparation of this prospectus and the registration statement of which this prospectus is a part.              will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. Goldman Sachs & Co. LLC 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.”

Dividend policy

  We anticipate paying cash dividends on our common stock subsequent to this offering. Please see “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 26 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”).



 

16


Table of Contents

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 as of and for the ten months ended December 31, 2017 is derived from audited 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 year ended December 31, 2017 has been prepared to give pro forma effect to (i) the Plan and related transactions and fresh-start accounting and (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”), 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 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 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.

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



 

17


Table of Contents

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.
(Successor)
    Berry LLC
(Predecessor)
 
    Ten Months
Ended
December 31, 
2017
    Two Months
Ended
February 28,
2017
    Year Ended
December 31,
 
        2016  
          (audited)        
         

($ in thousands)

       

Statements of Operations Data:

       

Oil, natural gas and NGL sales

  $ 357,928     $ 74,120     $ 392,345  

Electricity sales

    21,972       3,655       23,204  

(Losses) gains on oil and natural gas derivatives

    (66,900     12,886       (15,781

Marketing revenues

    2,694       633       3,653  

Other revenues

    3,975       1,424       7,570  

Lease operating expenses

    149,599       28,238       185,056  

Electricity generation expenses

    14,894       3,197       17,133  

Transportation expenses

    19,238       6,194       41,619  

Marketing expenses

    2,320       653       3,100  

General and administrative
expenses (1)

    56,009       7,964       79,236  

Depreciation, depletion and amortization

    68,478       28,149       178,223  

Impairment of long-lived assets

    —         —         1,030,588  

Taxes, other than income taxes

    34,211       5,212       25,113  

(Gains) losses on sale of assets and other, net

    (22,930     (183     (109

Interest expense

    18,454       8,245       61,268  

Other (income) expense, net

    (4,071     63       182  

Reorganization items, net (income) expense

    1,732       507,720       72,662  

Income tax (benefit) expense

    2,803       230       116  

Net (loss) income

    (21,068     (502,964     (1,283,196

Undeclared dividends on Series A preferred stock

    (18,248     n/a       n/a  

Net loss available to common stockholders

    (39,316     n/a       n/a  

Net (loss) income per share of common stock

       

Basic and Diluted

  $ (0.98     n/a       n/a  

Weighted average common stock outstanding

       

Basic and Diluted

    40,000       n/a       n/a  

Cash Flow Data:

       

Net cash provided by (used in)

       

Operating activities

    125,551       (30,301     12,345  

Capital expenditures

    (65,479     (3,158     (34,796

Acquisitions, sales of properties and other investing activities

    (15,046     25       53,612  

Balance Sheet Data:

       

(at period end)

       

Total assets

  $ 1,546,402     $ 1,561,038     $ 2,652,050  

Current portion of long-term debt

    —         —         891,259  

Long-term debt, net

    379,000       400,000       —    

Series A Preferred Stock

    335,000       335,000       —    

Stockholders’ and/or member’s
equity

    859,310       878,527       502,963  

Other Financial Data:

       

Adjusted EBITDA(2)

  $ 149,613     $ 28,845     $ 89,646  

Adjusted General and Administrative Expenses(3)

    23,865       7,964       79,236  

 

(1) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $32.1 million for the ten months ended December 31, 2017.


 

18


Table of Contents
(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 see “—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 see “—Non-GAAP Financial Measures.”

 

     Pro Forma  
     Year Ended
December 31,
 
     2017  
     ($ in thousands)  

Statements of Operations Data:

  

Oil, natural gas and NGL sales

   $ 394,206  

(Losses) gains on oil and natural gas derivatives

     (54,014

Lease operating expenses

     171,708  

Transportation expenses

     15,425  

General and administrative expenses(1)

     62,681  

Depreciation, depletion and amortization

     75,837  

Taxes, other than income taxes

     34,555  

Interest expense

     21,769  

Reorganization items, net (income) expense

     1,732  

Income tax (benefit) expense

     4,790  

Net (loss) income

     (36,089

 

(1) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $32.1 million for the year ended December 31, 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 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



 

19


Table of Contents

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.
(Successor)
     Berry LLC (Predecessor)  
    Ten Months
Ended December 31,
2017
     Two Months
Ended February 28,
2017
   

Year Ended

December 31,

 
             2016      
   

($ in thousands)

 

Adjusted EBITDA reconciliation to net income (loss):

        

Net income (loss)

  $ (21,068    $ (502,964   $ (1,283,196

Add (Subtract):

        

Depreciation, depletion, amortization and accretion

    68,478        28,149       178,223  

Exploration expense

    —          —         —    

Interest expense

    18,454        8,245       61,268  

Income tax expense (benefit)

    2,803        230       116  

Derivative (gain) loss

    66,900        (12,886     20,386  

Net cash received for derivative settlements

    3,068        534       9,708  

(Gain) on sale of assets and other

    (22,930      (183     (109

Impairments

    —          —         1,030,588  

Stock compensation expense

    1,851        —         —    

Restructuring costs

    30,325        —         —    
        

Reorganization items, net

    1,732        507,720       72,662  
 

 

 

    

 

 

   

 

 

 

Adjusted EBITDA

  $ 149,613      $ 28,845     $ 89,646  
 

 

 

    

 

 

   

 

 

 

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.



 

20


Table of Contents

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.
(Successor)
     Berry LLC
(Predecessor)
 
    Ten Months Ended
December 31,
2017
     Two Months
Ended February 28,
2017
     Year Ended
December 31, 2016
 
         
    ($ in thousands)  

Adjusted General and Administrative Expense reconciliation to general and administrative expenses:

         

General and administrative expenses

  $ 56,009      $ 7,964      $ 79,236  

Subtract:

         

Non-recurring restructuring and other costs

    30,325        —          —    
         

Non-cash stock compensation expense

    1,819        —          —    
 

 

 

    

 

 

    

 

 

 

Adjusted General and Administrative Expenses

  $ 23,865      $ 7,964      $ 79,236  
 

 

 

    

 

 

    

 

 

 


 

21


Table of Contents

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 as of December 31, 2017. The reserve estimates presented in the table below are based on a report 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 December 31, 2017(1)  
     San Joaquin and
Ventura basins
     Uinta basin      Piceance basin      East Texas basin      Total  

Proved developed reserves:

              

Oil (MMBbl)

     61        7        —          —          68  

Natural Gas (Bcf)

     —          47        42        12        100  

NGLs (MMBbl)

     —          1        —          —          1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMBoe)(2)(3)

     61        16        7        2        86  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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        237  

NGLs (MMBbl)

     —          1        —          —          1  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMBoe)(3)

     93        16        30        2        141  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

PV-10 ($MM)(4)

     998        84        24        7        1,114  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(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 $54.42 per Bbl ICE (Brent) for oil and NGLs and $2.98 per MMBtu NYMEX Henry Hub for natural gas at December 31, 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.”


 

22


Table of Contents
(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 year ended December 31, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $54.82 per Bbl and $3.11 per Mcf, respectively, resulting in an oil-to-gas ratio of over 17 to 1.
(4) For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—PV-10.” PV-10 does not give effect to derivatives transactions.

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 at December 31, 2017 (in millions):

 

     At December 31, 2017  

PV-10

     1,114  

Less: present value of future income taxes discounted at 10%

     (137
  

 

 

 

Standardized measure of discounted future net cash flows

     977  
  

 

 

 

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 and the ten months ended December 31, 2017 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.”



 

23


Table of Contents

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(4)     Berry Corp.
(Successor)
           Berry LLC
(Predecessor)
 
     Year Ended
December 31,
2017
    Ten Months Ended
December 31,
2017
           Two Months Ended
February 28,

2017
    Year Ended
December 31,
2016
 

Production Data:

             

Oil (MBbl/d)

     20.5       20.6            19.5       23.1  

Natural gas (MMcf/d)

     31.2       49.4            71.7       78.1  

NGLs (MBbl/d)

     0.6       2.0            5.2       3.6  

Average daily combined production
(MBoe/d)(1)

     26.3       30.9            36.6       39.7  

Oil (MBbl)

     7,471       6,318            1,153       8,463  

Natural gas (MMcf)

     11,382       15,119            4,232       28,577  

NGLs (MBbl)

     216       605            304       1,307  

Total combined production
(MBoe)(1)

     9,584       9,443            2,162       14,533  

Weighted average realized prices:

             

Oil with hedges (per Bbl)

   $ 48.37     $ 48.53          $ 47.40     $ 36.88  

Oil without hedges (per Bbl)

   $ 47.89     $ 48.05          $ 46.94     $ 35.83  

Natural gas (per Mcf)

   $ 2.82     $ 2.70          $ 3.42     $ 2.31  

NGLs (per Bbl)

   $ 20.00     $ 22.23          $ 18.20     $ 17.67  

Average Benchmark prices:

             

ICE (Brent) oil ($/Bbl)

   $ 54.82     $ 54.65          $ 55.72     $ 45.00  

NYMEX (WTI) oil ($/Bbl)

   $ 50.95     $ 50.53          $ 53.04     $ 43.32  

NYMEX Henry Hub natural gas
($/Mcf)

   $ 3.11     $ 3.00          $ 3.66     $ 2.46  

Average costs per Boe(2):

             

Lease operating expenses

   $ 17.92     $ 15.84          $ 13.06     $ 12.73  

Electricity generation expenses

   $ 1.89     $ 1.58          $ 1.48     $ 1.18  

Electricity sales

   $ (2.67   $ (2.33        $ (1.69   $ (1.60

Transportation expenses

   $ 1.61     $ 2.04          $ 2.86     $ 2.86  

Marketing expenses

   $ 0.31     $ 0.25          $ 0.30     $ 0.21  
             

Marketing revenues

   $ (0.35   $ (0.29        $ (0.29   $ (0.25
  

 

 

   

 

 

        

 

 

   

 

 

 

Total operating expenses

   $ 18.71     $ 17.09          $ 15.72     $ 15.13  
  

 

 

   

 

 

        

 

 

   

 

 

 

Taxes, other than income taxes

   $ 3.61     $ 3.62          $ 2.41     $ 1.73  

General and Administrative
Expenses(3)

   $ 6.54     $ 5.93          $ 3.68     $ 5.45  

Depreciation, depletion and
amortization

   $ 7.91     $ 7.25          $ 13.02     $ 12.26  

 

(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 year ended December 31, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $54.82 per Bbl and $3.11 per Mcf, respectively, resulting in an oil-to-gas ratio of over 17 to 1.


 

24


Table of Contents
(2) 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.
(3) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of approximately $2.77/Boe for the pro forma year ended December 31, 2017 and $3.40/Boe for the ten months ended December 31, 2017.
(4) Does not include the effects of the Hill Acquisition. We estimate that the additional production associated with the Hill Acquisition for the year ended December 31, 2017 was approximately 633,000 Boe or 1,734 Boe/d.


 

25


Table of Contents

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 crude oil future contract price declined from a high of over $100.16 per Bbl on June 24, 2014 to a low of $40.67 per Bbl on January 20, 2016. The Henry Hub spot price for natural gas has also declined since 2014. While oil 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;

 

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

 

    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;

 

    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;

 

26


Table of Contents
    refining and processing disruptions or bottlenecks;

 

    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 PUDs 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, including regulatory and permitting 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

 

27


Table of Contents

levels. If additional capital was 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 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 conditions 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. Our hedges are based on major oil and gas indexes, which may not fully reflect the prices we realize locally. Consequently, the price protection we receive may not fully offset local price declines.

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, and our commodity-price risk-management activities may prevent us from fully benefitting from price increases and may expose us to other risks.

As of March 31, 2018, we have hedged approximately 4.7 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.

 

28


Table of Contents

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.

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

 

29


Table of Contents

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;

 

    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 and, potentially acquisitions, 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

 

30


Table of Contents

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.

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 water 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.

 

31


Table of Contents

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 investments (including certain loans to others);

 

    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 or certain other obligations;

 

    transfer, sell or otherwise dispose of assets;

 

    repay or prepay certain indebtedness prior to the due date;

 

    enter into transactions with affiliates; and

 

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

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.

The borrowing base under the RBL Facility is subject to periodic redetermination.

The amount available to be borrowed under the RBL Facility is subject to a borrowing base, and will be redetermined semiannually on or about each May 1 and November 1, and will depend on the volumes of our estimated proved oil and natural gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent of the RBL Facility. We may request one additional redetermination between each regularly scheduled redetermination and the administrative agent and the lenders may request one additional redetermination between each regularly scheduled redetermination. Furthermore, our borrowing base is subject to automatic reductions due to certain asset sales and hedge terminations, the incurrence of certain other debt and other events as provided in the RBL Facility. For example, the RBL Facility currently provides that to the extent we incur certain unsecured indebtedness, our borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt that exceeds the amount, if any, of certain other debt that is being refinanced by such unsecured debt. Redeterminations will be based upon a number of factors, including commodity prices and reserve levels. We could be required to repay a portion of the RBL Facility to the extent that after a redetermination our outstanding borrowings at such time exceed the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the facility and an acceleration of the loans outstanding under the facility, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results.

 

32


Table of Contents

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.

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 to produce steam for our operations. Viable contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.

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. To further offset our costs, we sell surplus power to California utility companies produced by three of our cogeneration facilities under long-term contracts. These facilities are dependent on viable contracts for the sale of electricity. Should we lose, be unable to renew on favorable terms, or be unable to replace such contracts, we may be unable to realize the cost offset currently received. Furthermore, 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

 

33


Table of Contents

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.”

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 the 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. The RBL Facility and our 2026 Notes currently restrict 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.

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.

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 ten months ended December 31, 2017, sales of oil, natural gas and NGLs to Tesoro

 

34


Table of Contents

Corporation, Phillips 66 and Kern Oil & Refining accounted for approximately 37%, 34% and 15%, respectively, of our sales. For the two months ended February 28, 2017, sales of oil, natural gas and NGLs to Tesoro Corporation and Phillips 66 accounted for approximately 36% and 31%, 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.

 

35


Table of Contents

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 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. 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 see “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

 

36


Table of Contents

commonly referred to as the Tax Cuts and Jobs Act (the “Tax 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. Any future legislation could potentially adversely affect our business, operating results and financial condition.

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

 

37


Table of Contents

significantly increase our capital, compliance and operating costs and could also reduce demand for the oil and natural gas we produce. The cost of acquiring 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. 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

 

38


Table of Contents

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.

We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If 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. 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 are not 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 are not 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.

 

39


Table of Contents

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.

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

 

40


Table of Contents

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 “Risks Related to the Offering and our Capital Stock—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 common stock may have limited or no ability to sell their shares. In addition, the initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering.

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 our common stock will be established or that, if established, a market will be sustained. Therefore, holders of our common stock may be unable to sell their shares.

The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops for our common stock may be affected by, numerous factors, many of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholders and representative of the underwriters, based on numerous factors that we discuss in “Underwriting (Conflicts of Interest),” and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The following factors, among other things, could impact our stock price: our limited trading history; our limited trading volume, the concentration of holdings of our common stock; the lack of comparable historical financial information, in certain material respects, given the adoption of fresh-start accounting; actual or anticipated variations in our financial and operating results and cash flows; the nature and content of our earnings releases, other public announcements and our filings with the SEC; the failure of research analysts to cover our common stock; changes in recommendations or withdrawal of research coverage, by equity research analysts; speculation in the press or investment community; sales of our common stock by us, the selling stockholders or other stockholders, or the perception that such sales may occur; changes in accounting principles, policies, guidance, interpretations or standards; additions or departures of key management personnel; actions by our stockholders; announcements or events that impact our assets, customers, competitors or markets; domestic and international economic, legal and regulatory factors unrelated to our performance; business conditions in our markets and the general state of the securities markets and the market for energy-related stocks; 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 common stock or as to the liquidity of the trading market for our common stock. If an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

 

41


Table of Contents

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 Convertible Preferred Stock, par value $0.001 per share (“Series A Preferred Stock”), which has 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, hostile takeovers 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 stock 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 be unavailable 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, 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.

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

 

42


Table of Contents

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’ option to purchase additional shares is fully exercised. We have entered into a registration rights agreement with certain of our stockholders, including the selling stockholders (the “Registration Rights Agreement”), 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. As of the Effective Date, there were 25,253,908 shares of our common stock and 29,776,872 shares of Series A Preferred Stock outstanding that were owned by stockholders with rights under the Registration Rights Agreement. For more information see “Description of Capital Stock—Registration Rights.”

The issuance of any securities for acquisitions, 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.

 

43


Table of Contents

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 may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

The Certificate of Incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common 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.

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(b) of the Sarbanes-Oxley Act or any new requirements adopted by 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, 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

 

44


Table of Contents

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 and rules promulgated by the            , 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 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(b) 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. Further, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

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 the financial information and 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.

 

45


Table of Contents

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.

Effective internal controls are necessary for us to provide reliable financial reports, safeguard our assets, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports, safeguard our assets or prevent fraud, our reputation and operating results could be harmed. 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. Further, 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 herein), 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 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.

 

46


Table of Contents

Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our Certificate of Incorporation 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 (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders, (iii) any action asserting a claim against us, our directors, officers or employees arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our Certificate of Incorporation or our Bylaws or (iv) any action asserting a claim against us, our directors, officers or employees that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having subject matter jurisdiction and personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our common stock will be deemed to have notice of, and consented to, the provisions of our Certificate of Incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

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. Goldman Sachs & Co. LLC and Wells Fargo Securities, LLC, 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 (Conflicts of Interest)” 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.

 

47


Table of Contents

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;

 

48


Table of Contents
    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.

 

49


Table of Contents

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 for general corporate purposes.

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.

 

50


Table of Contents

DIVIDEND POLICY

We have not paid dividends on our common stock to date; however, we anticipate paying cash dividends on our common stock subsequent to this offering.

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 Certificate of Designation of Series A Convertible Preferred Stock of Berry Petroleum Corporation (the “Series A Certificate of Designation”)), with such dividends compounding quarterly. On 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 the option of our board of directors, 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.

In March 2018, the board of directors approved a cumulative paid-in-kind dividend on the Series A preferred stock for the periods through December 31, 2017. The cumulative dividend was 0.050907 per share, or approximately 1,825,000 shares in total. Also in March 2018, the board of directors approved a $0.158 per share, or approximately $5.6 million, cash dividend on the Series A preferred stock for the quarter ended March 31, 2018. Each dividend was paid in April 2018 to stockholders of record as of March 15, 2018.

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.

 

51


Table of Contents

CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 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 December 31, 2017  
     Actual      As Adjusted      As Further
Adjusted (1)
 
     (in millions)  

Cash and cash equivalents

   $ 34      $ 47      $               
  

 

 

    

 

 

    

 

 

 

Debt:

        

RBL Facility(2)

   $ 379      $ —        $  
        

Senior Notes due 2026

     —          400     
  

 

 

    

 

 

    

 

 

 

Total debt

     379        400     

Stockholders’ Equity

        

Series A Preferred Stock—$0.001 par value, 250,000,000 shares authorized and 35,845,001 shares issued and outstanding (actual, as adjusted and as further adjusted)(3)

     335        335     

Common Stock—$0.001 par value, 750,000,000 shares authorized and 32,920,000 shares issued and outstanding (actual and as adjusted);             shares authorized and shares issued and outstanding (as further adjusted)

     524        524     
  

 

 

    

 

 

    

 

 

 

Total stockholders’ equity

     859        859     
  

 

 

    

 

 

    

 

 

 

Total capitalization

   $ 1,238      $ 1,259      $  
  

 

 

    

 

 

    

 

 

 

 

(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                    , 2018, the outstanding balance under the RBL Facility was approximately $            million, and we had cash and cash equivalents of approximately $            million.
(3) As of                     , 2018, we had              shares of Series A Preferred Stock issued and outstanding.

 

52


Table of Contents

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 December 31, 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 of $              (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of December 31, 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 December 31, 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.

The following table summarizes, on an adjusted pro forma basis as of December 31, 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.

 

53


Table of Contents
(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 that would be issuable if holders exercised their option to convert shares of Series A Preferred Stock immediately after the consummation of this offering or shares of common stock reserved for issuance under our 2017 Incentive Plan.

 

54


Table of Contents

SELECTED HISTORICAL FINANCIAL DATA

The following table shows the selected historical financial information, for the periods and as of the dates indicated, of our predecessor company (Berry LLC) and successor company (Berry Corp.). The selected historical financial information as of and for the year ended December 31, 2016 is derived from the audited historical financial statements of our predecessor company included elsewhere in this prospectus. The selected historical financial information as of and for the two months ended February 28, 2017 is derived from audited financial statements of our predecessor company included elsewhere in this prospectus. The selected historical financial information as of and for the ten months ended December 31, 2017 is derived from audited consolidated financial statements of the successor company 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 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. 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 financial statements of our predecessor and accompanying notes included elsewhere in this prospectus.

 

    Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
    Ten Months
Ended 

December 31,
2017
    Two Months
Ended

February 28,
2017
   

 

Year Ended
December 31,

2016

 
       
         

(audited)

       
          ($ in thousands)        

Statements of Operations Data:

       

Oil, natural gas and NGL sales

  $ 357,928     $ 74,120     $ 392,345  

Electricity sales

    21,972       3,655       23,204  

(Losses) gains on oil and natural gas derivatives

    (66,900     12,886       (15,781

Marketing revenues

    2,694       633       3,653  

Other revenues

    3,975       1,424       7,570  

Lease operating expenses

    149,599       28,238       185,056  

Electricity generation expenses

    14,894       3,197       17,133  

Transportation expenses

    19,238       6,194       41,619  

Marketing expenses

    2,320       653       3,100  

General and administrative expenses(1)

    56,009       7,964       79,236  

Depreciation, depletion and amortization

    68,478       28,149       178,223  

Impairment of long-lived assets

                1,030,588  

Taxes, other than income taxes

    34,211       5,212       25,113  

(Gains) losses on sale of assets and other, net

    (22,930     (183     (109

Interest expense

    18,454       8,245       61,268  

Other (income) expense, net

    (4,071     63       182  

Reorganization items, net (income) expense

    1,732       507,720       72,662  

 

55


Table of Contents
    Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
    Ten Months
Ended 

December 31,
2017
    Two Months
Ended

February 28,
2017
   

 

Year Ended
December 31,

2016

 
       
         

(audited)

       
          ($ in thousands)        

Income tax (benefit) expense

    2,803       230       116  

Net (loss) income

    (21,068     (502,964     (1,283,196

Undeclared dividends on Series A preferred stock

    (18,248     n/a       n/a  

Net loss available to common stockholders

    (39,316     n/a       n/a  

Net income per share of common stock

       

Basic and Diluted

  $ (0.98     n/a       n/a  

Weighted average common stock outstanding

       

Basic and Diluted

    40,000       n/a       n/a  

Cash Flow Data:

       

Net cash provided by (used in)

       

Operating activities

  $ 125,551     $ (30,301   $ 12,345  

Capital expenditures

    (65,479     (3,158     (34,796

Acquisitions, sales of properties and other investing activities

    (15,046     25       53,612  

Balance Sheet Data:

       

(at period end)

       

Total assets

  $ 1,546,402     $ 1,561,038     $ 2,652,050  

Current portion of long-term debt

    —         —         891,259  

Long-term debt, net

    379,000       400,000       —    

Series A Preferred Stock

    335,000       335,000       —    

Stockholders’ and/or members’ equity

    859,310       878,527       502,963  

Other Financial Data:

       

Adjusted EBITDA(2)

  $ 149,613     $ 28,845     $ 89,646  

Adjusted General and Administrative Expenses(3)

    23,865       7,964       79,236  

 

(1) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $32.1 million for the ten months ended December 31, 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 see “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 see “Prospectus Summary—Summary Historical and Pro Forma Financial Information—Non-GAAP Financial Measures.”

 

56


Table of Contents

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 statement of operations is presented for the year ended December 31, 2017. This unaudited pro forma condensed consolidated financial information should be read in conjunction with Berry Corp.’s historical consolidated financial statements as of and for the ten months ended December 31, 2017 and with Berry LLC’s historical financial statements for the two months ended February 28, 2017 included in this prospectus.

The unaudited pro forma condensed consolidated statement of operations gives effect to (1) the Plan and fresh-start accounting and (2) the Hugoton Disposition as if each had been completed as of January 1, 2017. 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 statement is for informational and illustrative purposes only and is not necessarily indicative of the financial results that would have been had the events and transactions occurred on the dates assumed, nor is such financial statement necessarily indicative of the results of operations in future periods. The unaudited pro forma condensed consolidated financial statement does 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, fresh-start accounting and 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 U.S. Bankruptcy Code (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 (the “Confirmation Order”).

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 and Fresh-Start Accounting

On the Effective Date, Berry LLC 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, dated February 28, 2017,

 

57


Table of Contents
 

between Linn Acquisition Company, LLC and Berry Corp. (the “Assignment Agreement”). Under the Assignment Agreement, Berry LLC became a wholly owned operating subsidiary of Berry Corp.

 

    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 a 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 of our consolidated financial statements.

 

    The holders of Berry LLC’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 (i) either 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 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 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. 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. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy, which Berry LLC has fully reserved.

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

 

58


Table of Contents

confirmation of the Plan. The Company determined a value to be assigned to the equity of the emerging entity as of the date of adoption of fresh-start accounting. 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. 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 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. 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, 2017. Preparation of an actual valuation with assumptions and economic data as of January 1, 2017 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.

 

59


Table of Contents

BERRY PETROLEUM CORPORATION

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR YEAR ENDED DECEMBER 31, 2017

(in thousands)

 

     Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
    Plan of
Reorganization
and Fresh-
Start
Accounting
Adjustments
    Hugoton
Disposition
Adjustments
     Berry Corp.
(Successor)
Pro Forma
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended
February 28,
2017
        

Revenues and other:

             

Oil, natural gas and NGL sales

   $ 357,928     $ 74,120     $ —       $ (37,842 )(f)     $ 394,206  

Electricity sales

     21,972       3,655       —         —          25,627  

Gains (losses) on oil and natural gas derivatives

     (66,900     12,886       —         —          (54,014

Marketing revenues

     2,964       633       —         —          3,327  

Other revenues

     3,975       1,424       —         (5,265 )(f)       134  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 
     319,669       92,718       —         (43,107      369,281  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Expenses:

             

Lease operating expenses

     149,599       28,238       —         (6,129 )(g)       171,708  

Electricity generation expenses

     14,894       3,197       —         —          18,091  

Transportation expenses

     19,238       6,194       —         (10,007 )(g)       15,425  

Marketing expenses

     2,320       653       —         —          2,972  

General and administrative expenses

     56,009       7,964       —         (1,292 )(g)       62,681  

Depreciation, depletion and amortization

     68,478       28,149       (14,105 )(a)      (6,685 )(h)       75,837  

Taxes, other than income taxes

     34,211       5,212       —         (4,868 )(g)       34,555  

Gains on sale of assets and other, net

     (22,930     (183     —         22,930 (h)       (183
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 
     321,819       79,424       (14,105     (6,050      381,087  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Other income and (expenses):

             

Interest expense, net of amounts capitalized

     (18,454     (8,245     4,930 (b)      —          (21,769

Other, net

     4,071       (63     —         —          4,008  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 
     (14,383     (8,308     4,930       —          (17,761
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Reorganization items, net

     (1,732     (507,720     507,720 (c)      —          (1,732

(Loss) income before income taxes

     (18,265     (502,734     526,755       (37,056      (31,299

Income tax expense (benefit)

     2,803       230       (3,238     4,994 (d)       4,790  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income (loss)

     (21,068     (502,964     529,993       (42,050      (36,089
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Undeclared preferred stock dividend

     (18,248     n/a       (3,585 )(e)      —          (21,833
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income (loss) available to common stockholders

   $  (39,316     (502,964   $ 526,408     $ (42,050    $ (57,922
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income (loss) per share:

             

Basic

   $ (0.98     n/a          $ (1.45
  

 

 

   

 

 

        

 

 

 

 

60


Table of Contents

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

1.    Basis of Presentation

The accompanying unaudited pro forma condensed consolidated statement of operations and explanatory notes present the financial information of Berry Corp. assuming the events and transactions had occurred on January 1, 2017.

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

Predecessor represents the historical statements of operations of Berry LLC for the two months ended February 28, 2017.

Successor represents the historical consolidated statements of operations of Berry Corp. for the ten months ended December 31, 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

Plan of Reorganization and Fresh-Start Accounting Adjustments

The adjustments included in the unaudited pro forma condensed 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 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.

(b)    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 accruing at a rate of 3.75% per annum on the amount subject to draw 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  
  

 

 

 

 

61


Table of Contents

(c)    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

   $ (421,774

Fresh-start valuation adjustments

     920,699  

Legal and other professional advisory fees

     19,481  

Other

     (10,686
  

 

 

 

Pro forma adjustment to eliminate reorganization items for the two months ended February 28, 2017

   $ 507,720  
  

 

 

 

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

For the year ended December 31, 2017, the effective tax rate used to calculate income tax expense was (15.3)%. The effective tax rate differed from the federal statutory rate of 35% due to the impact of state taxes, the change in the valuation allowance and the tax reform rate change.

(d)    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 two-month period ended February 28, 2017, any tax benefit that would potentially be realizable as a result of the new tax status and losses incurred during the year has 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.

(e) Reflects the undeclared and accreted dividends on the Series A Preferred Stock assuming that we emerged from bankruptcy and the Series A Preferred Stock was issued on January 1, 2017 rather than the Effective Date.

Hugoton Disposition Adjustments

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

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

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

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

 

62


Table of Contents

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. 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, our predecessor company, and following the Effective Date, we are referring to Berry Corp. and its subsidiary, Berry LLC, together, the successor company, as applicable.

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. 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:

 

    high oil content, which makes up approximately 79% of our production;

 

    favorable Brent-influenced crude oil pricing dynamics;

 

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

 

    stable and predictable development and production cost structures;

 

             years of low-risk identified development drilling opportunities with attractive full-cycle economics; and

 

    potential in-basin strategic opportunities to expand our existing inventory with new locations of substantially similar geology and economics.

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 for PUD wells drilled and completed in California will average less than $450,000 per well.

 

63


Table of Contents

We also maintain 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.

As of December 31, 2017, we had estimated total proved reserves of 141,385 MBoe, of which approximately 66% were located in California and 57% were proved developed producing reserves. For the three months ended December 31, 2017, we had average production of approximately 27.9 MBoe/d, of which approximately 79% was oil.

Chapter 11 Bankruptcy and Our Emergence

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 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 Effective Date, Berry LLC 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 the Assignment Agreement. Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.

 

    The holders of claims under 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 a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.

 

64


Table of Contents
    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 of our consolidated financial statements.

 

    The holders of Berry LLC’s 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 the Cash Distribution Pool and (ii) specified rights to participate 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 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. 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. 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 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. Each share of Series A Preferred Stock may be converted into one share of common stock, subject to dilution adjustments, (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 Series A 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) Adjusted EBITDA; (b) operating expenses; (c) environmental, health & safety (“EH&S”)

 

65


Table of Contents

results; (d) taxes, other than income taxes; (e) general and administrative expenses; (f) production; and (g) levered free cash flow.

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.

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 expense 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, we do not include these taxes in our operating expenses.

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.

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.

Levered free cash flow

Levered free cash flow reflects our financial flexibility; and we use it to plan our internal growth capital expenditures. We define levered free cash flow as Adjusted EBITDA less capital expenditures,

 

66


Table of Contents

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 our 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 is not 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 balance sheet at December 31, 2016.

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. We have also completed the following financing activities post-emergence.

New RBL Facility

On July 31, 2017, Berry LLC, as borrower, entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base, and an initial commitment of $500 million. In connection with the 2018 Notes Offering, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that

 

67


Table of Contents

reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. As of March 31, 2018, we had no borrowings and approximately $7 million in letters of credit outstanding under the RBL Facility. The RBL Facility also provides a letter of credit sub-facility 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 December 31, 2017, prior to our sale of the 2026 Notes, we had $379 million in borrowings and $21 million in letters of credit outstanding under the RBL Facility. For additional information, please see “—Liquidity and Capital Resources—Debt—New RBL Facility.”

Senior Unsecured Notes Offering

In February 2018, we closed the 2018 Notes Offering of $400 million in aggregate 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, 2017 and 2016, our capital expenditures were approximately $73 million and $26 million, respectively, on an accrual basis excluding acquisitions. Beginning in 2015 and carrying forward until the commencement of the Chapter 11 Proceeding in May 2016, LINN Energy and our predecessor company undertook a number of actions, including minimizing capital expenditures and further reducing recurring operating expenses in an attempt to decrease its and our predecessor company’s level of indebtedness and maintain its liquidity at levels sufficient to meet their respective commitments. Despite 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.

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 92% over our 2017 capital expenditures, including the successor and predecessor periods, of approximately $73 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 exclusively 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 drilling opportunities in Colorado and Utah 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 consistent pace of drilling throughout the year.

 

68


Table of Contents

The table below sets forth by basin the allocation of our actual 2017 capital expenditures and the expected allocation of our 2018 capital expenditure budget assuming total capital expenditures of $135 - $145 million.

 

     Capital Expenditure by Area  
     2018 Budget      2017 Actual  
     (in millions)  

California

   $ 111-116      $ 71  

Uinta

     8-10        1  

Piceance

     11-13        1  

East Texas

     —          —    

Corporate

     5-6        —    
  

 

 

    

 

 

 

Total

   $ 135-145      $ 73  
  

 

 

    

 

 

 

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.

Chevron North Midway-Sunset Acquisition

In April 2018, we completed the Chevron North Midway-Sunset Acquisition. We assumed a drilling commitment of approximately $34.5 million over a 5-year term and would assume a further commitment if we exercise our option. 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. This transaction is consistent with our business strategy to investigate areas beyond our known productive areas. See “Prospectus Summary—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.”

Commodity Derivatives and Contracts

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 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.

 

69


Table of Contents

Our open derivative positions as of December 31, 2017 were as follows:

 

     2018      2019      2020  

Sold NYMEX WTI call options:

        

Hedged volume (MBbls)

     900        840        390  

Weighted average price ($/Bbl)

   $ 55.00      $ 57.32      $ 60.00  

Oil positions:

        

Fixed Price Swaps (NYMEX WTI/ICE BRENT)

        

Hedged volume (MBbls)

     5,360        4,197        —    

Weighted average price ($/Bbl)

   $ 52.80      $ 52.05      $ —    

Oil basis differential positions:

        

ICE Brent – NYMEX WTI basis swaps

        

Hedged volumes (MBbls)

     1,460        1,095        —    

Weighted average price ($/Bbl)

   $ 1.21      $ 1.17      $ —    

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

 

     Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended

February 28,
2017
    Year Ended
December 31,
2016
 

Crude Oil (per Bbl):

        

Realized price, before the effects of derivative settlements

   $ 48.05     $ 46.94     $ 35.83  

Effects of derivative settlements

   $ 0.48     $ 0.46     $ 1.05  

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 March 31, 2018, we have hedged approximately 4.7 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,

 

70


Table of Contents

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 net operating loss carryforwards for the periods prior to February 28, 2017.

On December 22, 2017, the Tax Act was enacted. The Tax Act contains significant changes to U.S. income tax and related laws, including a reduction in the corporate income tax rate, immediate deductions for the cost of acquired qualified property (subject to certain phase-out provisions), and a limitation on the interest expense deduction. We evaluated the provisions of the Tax Act, most of which became effective January 1, 2018, and determined the net impact on our financial statements was to reflect a valuation allowance in excess of net deferred tax assets of $1.9 million. Over the long term, the Tax Act is expected to be favorable to us and should result in the deferral of cash tax payments as compared to when such payments would otherwise have been due on our taxable income.

Business Environment and Market Conditions

The oil and gas industry is heavily influenced by commodity prices. Since the latter half of 2014, commodity prices have declined and remained at relatively low levels through the middle of 2017 but have generally risen since then. For example, the Brent crude oil futures contract prices declined from a high of over $100.16 per Bbl on June 24, 2014 to a low of $40.67 per Bbl on January 20, 2016. The Henry Hub spot price for natural gas has also declined since 2014. While oil 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.”

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

 

     2017      Year Ended
December 31,
 
        2016  

ICE (Brent) oil ($/Bbl)

   $ 54.82      $ 45.00  

NYMEX (WTI) oil ($/Bbl)

   $ 50.95      $ 43.32  

NYMEX Henry Hub natural gas ($/MMBtu)

   $ 3.11      $ 2.46  

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. Recently, there is a closer correlation of actual 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.

 

71


Table of Contents

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 substantially more natural gas for our steamfloods and power generation than we produce and sell. 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.

 

72


Table of Contents

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)
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended
February 28,
2017
    Year Ended
December 31,
 
         2016  

Production Data:

        

Oil (MBbl/d)

     20.6       19.5       23.1  

Natural gas (MMcf/d)

     49.4       71.7       78.1  

NGLs (MBbl/d)

     2.0       5.2       3.6  

Average daily combined production (MBoe/d)(1)

     30.9       36.6       39.7  

Oil (MBbl)

     6,318       1,153       8,463  

Natural gas (MMcf)

     15,119       4,232       28,577  

NGLs (MBbl)

     605       304       1,307  

Total combined production (MBoe)(1)

     9,443       2,162       14,533  

Weighted average realized prices:

        

Oil with hedges (per Bbl)

   $ 48.53     $ 47.40     $ 36.88  

Oil without hedges (per Bbl)

   $ 48.05     $ 46.94     $ 35.83  

Natural gas (per Mcf)

   $ 2.70     $ 3.42     $ 2.31  

NGLs (per Bbl)

   $ 22.23     $ 18.20     $ 17.67  

Average Benchmark prices:

        

ICE (Brent) oil ($/Bbl)

   $ 54.65     $ 55.72     $ 45.00  

NYMEX (WTI) oil ($/Bbl)

   $ 50.53     $ 53.04     $ 43.32  

NYMEX Henry Hub natural gas ($/Mcf)

   $ 3.00     $ 3.66     $ 2.46  

Average costs per Boe(2):

        

Lease operating expenses

   $ 15.84     $ 13.06     $ 12.73  

Electricity generation expenses

   $ 1.58     $ 1.48     $ 1.18  

Electricity sales

   $ (2.33   $ (1.69   $ (1.60

Transportation expenses

   $ 2.04     $ 2.86     $ 2.86  

Marketing expenses

   $ 0.25     $ 0.30     $ 0.21  

Marketing revenues

   $ (0.29   $ (0.29   $ (0.25

Total operating expenses

   $ 17.09     $ 15.72     $ 15.13  

Taxes, other than income taxes

   $ 3.62     $ 2.41     $ 1.73  

General and Administrative Expenses(3)

   $ 5.93     $ 3.68     $ 5.45  

Depreciation, depletion and amortization

   $ 7.25     $ 13.02     $ 12.26  

 

(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 year ended December 31, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $54.82 per Bbl and $3.11 per Mcf, respectively, resulting in an oil-to-gas ratio of over 17 to 1
(2)

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

 

73


Table of Contents
  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.
(3) Includes non-recurring restructuring and other costs and non-cash stock compensation expense of approximately $3.40/Boe for the ten months ended December 31, 2017.

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

 

     Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended
February 28,
2017
     Year Ended
December 31,
 
          2016  

Average daily production (MBoe/d):

         

California(1)

     18.0       17.0        20.2  

Hugoton basin(2)

     4.5       10.8        9.5  

Uinta basin

     5.3       5.4        5.8  

Piceance basin

     2.0       2.3        2.9  

East Texas

     1.1       1.1        1.3  
  

 

 

   

 

 

    

 

 

 
     30.9       36.6        39.7  

 

(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.

Average daily production volumes decreased in 2017, including the successor and predecessor periods, by 7.9 MBoe/d, or 20%, when compared to the year ended December 31, 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 decrease in average daily production volumes in 2017 compared to 2016 was primarily due to the sale of the Hugoton assets and the limited capital investment in 2016 and early 2017, as well as the shut-in of uneconomic thermal Diatomite wells in California in early 2016 and uneconomic wells in Utah in late 2016, offset by increasing production from the remaining thermal Diatomite wells and return to production of Utah wells throughout 2017 and increased capital investment beginning in mid-2017.

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.

 

74


Table of Contents

Results of Operations

Ten Months Ended December 31, 2017, Two Months Ended February 28, 2017 and Year Ended December 31, 2016

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

 

     Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
     Ten Months
Ended
  December 31,  
2017
    Two Months
Ended

February 28,
2017
     Year Ended
December 31,
2016
 
           (audited)         
     (in thousands)  

Revenues and other:

       

Oil, natural gas and NGL sales

   $ 357,928     $ 74,120      $ 392,345  

Electricity sales

     21,972       3,655        23,204  

Gains (losses) on oil and natural gas derivatives

     (66,900     12,886        (15,781

Marketing revenues

     2,694       633        3,653  

Other revenues

     3,975       1,424        7,570  
  

 

 

   

 

 

    

 

 

 
     319,669     $ 92,718        410,991  
  

 

 

   

 

 

    

 

 

 

Expenses:

       

Lease operating expenses

     149,599       28,238        185,056  

Electricity generation expenses

     14,894       3,197        17,133  

Transportation expenses

     19,238       6,194        41,619  

Marketing expenses

     2,320       653        3,100  

General and administrative expenses

     56,009       7,964        79,236  

Depreciation, depletion and amortization

     68,478       28,149        178,223  

Impairment of long-lived assets

     —         —          1,030,588  

Taxes, other than income taxes

     34,211       5,212        25,113  

Gains on sale of assets and other, net

     (22,930     (183      (109
  

 

 

   

 

 

    

 

 

 
     321,819       79,424        1,559,959  

Other income and (expenses)

       

Interest expense

     (18,454     (8,245      (61,268

Other income, net

     4,071       (63      (182

Reorganization items, net

     (1,732     (507,720      (72,662
  

 

 

   

 

 

    

 

 

 

Loss before income taxes

     (18,265     (502,734      (1,283,080

Income tax expense (benefit)

     2,803       230        116  
  

 

 

   

 

 

    

 

 

 

Net income (loss)

   $ (21,068   $ (502,964    $ (1,283,196
  

 

 

   

 

 

    

 

 

 

Revenues and Other

Oil, natural gas and NGL sales increased in 2017, including the successor and predecessor periods, by $40 million, or 10%, when compared to the year ended December 31, 2016 due to an increase in realized oil and NGL prices and an increased mix of oil production compared to gas production as a result of the Hill Acquisition and Hugoton Disposition, partially offset by decreased natural gas and NGL production.

Electricity sales increased in 2017, including the successor and predecessor periods, by $2 million, or 10%, when compared to the year ended December 31, 2016 primarily due to higher volumes sold externally because of lower internal usage related to lower steamflood production activity, as well as higher prices.

 

75


Table of Contents

Losses on oil and natural gas derivatives increased in 2017, including the successor and predecessor periods, by $38 million, or 242%, when compared to the year ended December 31, 2016 primarily due to increased hedging activity, a portion of which was required by our credit facilities, and improved commodity prices relative to the fixed prices of our derivative contracts.

Marketing revenues in 2017, including the successor and predecessor periods, were comparable to the year ended December 31, 2016.

Other revenues decreased in 2017, including the successor and predecessor periods, by $2 million, or 29%, when compared to the year ended December 31, 2016 due to a decrease in helium gas sales as a result of the Hugoton Disposition.

Expenses

Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased in 2017, including the successor and predecessor periods, by $7 million, or 4%, when compared to the year ended December 31, 2016 primarily due to the effect of the Hugoton Disposition (natural gas production) and the Hill Acquisition (oil production), reflecting higher operating expenses associated with natural gas production compared to oil production, and our production decline as a result of decreased development 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 increased in 2017, including the successor and predecessor periods, by $1 million, or 6%, when compared to the year ended December 31, 2016, primarily due to the increase in the price of natural gas used in steam generation, for which electricity generation is a by-product.

Transportation expenses decreased in 2017, including the successor and predecessor periods, by $16 million, or 39%, when compared to the year ended December 31, 2016, primarily due to the cancellation of uneconomic contracts in the Chapter 11 Proceedings and the Hugoton Disposition, which required significant transportation expenses.

Marketing expenses in 2017, including the successor and predecessor periods, were comparable to the year ended December 31, 2016.

General and administrative expenses decreased in 2017, including the successor and predecessor periods, by $15 million, or 19%, when compared to the year ended December 31, 2016 primarily due to the management change in conjunction with our emergence from bankruptcy. The reduction in absolute dollars offset by lower production resulted in higher general and administrative expenses per Boe for the year ended December 31, 2017 when compared to the same period in 2016. General and administrative expenses include non-recurring restructuring and other costs of approximately $30 million and non-cash stock compensation costs of approximately $2 million for the ten months ended December 31, 2017. General and administrative expenses in 2016 mainly consisted of allocations from our parent company at the time.

Depreciation, depletion and amortization decreased in 2017, including the successor and predecessor periods, by $82 million, or 46%, when compared to the year ended December 31, 2016, primarily due to the fair market revaluation of our assets in fresh-start accounting resulting in a lower

 

76


Table of Contents

depreciable asset base. The reduction in absolute dollars offset by lower production resulted in lower depreciation, depletion and amortization per Boe for the year ended December 31, 2017, including successor and predecessor periods, 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)
 
     Ten Months
Ended
  December 31,   
2017
    Two Months
Ended

February 28,
2017
     Year Ended
December 31,
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  

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 year ended December 31, 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)
 
     Ten Months
Ended
  December 31,   
2017
    Two Months
Ended

February 28,
2017
     Year Ended
December 31,
2016
 
           (in thousands)         

Severance taxes

   $ 8,992     $ 1,540      $ 7,968  

Ad valorem taxes

     11,599       2,108        10,951  

Greenhouse gas allowances

     13,620       1,564        6,063  

Other

     —         —          131  
  

 

 

   

 

 

    

 

 

 
   $ 34,211     $ 5,212      $ 25,113  
  

 

 

   

 

 

    

 

 

 

Taxes, other than income taxes, increased in 2017, including the successor and predecessor periods, by $14 million, or 57%, compared to the year ended December 31, 2016. Severance taxes, which are a function of revenues generated from production in certain jurisdictions, increased in 2017, including successor and predecessor periods, by $2.5 million, or 32%, primarily because of increased revenues. Ad valorem taxes, which are based on the value of reserves and production equipment, and vary by location, increased in 2017, including the successor and predecessor periods, by $3 million, or 25%, compared to the year ended December 31, 2016, as a result of higher estimated valuations by various tax authorities based on increased commodity prices. Greenhouse gas allowances increased in 2017, including the successor and predecessor periods, by $9 million, or 150%, when compared to the year ended December 31, 2016, primarily due to increased development activity in the second half of 2017 and an increase in the price of allowances.

 

77


Table of Contents

Gains on sale of assets and other, net

Gains on sales of assets and other, net increased in 2017, including the successor and predecessor periods, by $23 million, compared to the year ended December 31, 2016, primarily due to the Hugoton Disposition.

Other Income and (Expenses)

 

     Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended
February 28,
2017
     Year Ended
December 31,
2016
 
           (in thousands)         

Interest expense

   $ (18,454   $ (8,245    $ (61,268

Other income, net

     4,071       (63      (182
  

 

 

   

 

 

    

 

 

 
   $ (14,383   $ (8,308    $ (61,450
  

 

 

   

 

 

    

 

 

 

Interest expense decreased in 2017, including the successor and predecessor periods, by $35 million, or 56%, compared to the year ended December 31, 2016, due to reduced debt resulting from the bankruptcy. Other income, net, for the year ended December 31, 2017, primarily consists of a refund of a federal tax overpayment from a prior year.

Income tax expense (benefit)

On the Effective Date, upon consummation of the Plan, we became subject to federal and state income taxes as a C corporation. Prior to the consummation of the Plan, we were treated as a disregarded entity for federal and state income tax purposes as a limited liability company, 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, we did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for our operations prior to the Effective Date.

Income tax expense increased in 2017, including the successor and predecessor periods, by $3 million when compared to the year ended December 31, 2016 as a result of federal and state alternative minimum tax current taxes and a valuation allowance in excess of net deferred tax assets of $1.9 million due to the impact of applying the Tax Act legislation at the end of 2017.

Reorganization items, net

Reorganization items, net, increased in 2017, including the successor and predecessor periods by $437 million, or 600%, compared to the year ended December 31, 2016, primarily due to the impact from the application of fresh-start accounting in conjunction with our emergence from bankruptcy during the two months ended February 28, 2017, partially offset by the gain on settlement of liabilities subject to compromise. Reorganization items represent costs and income directly associated with the Chapter 11 Proceeding since 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.

 

78


Table of Contents

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

 

     Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended
February 28,
2017
     Year Ended
December 31,
2016
 
           (in thousands)  

Gain on settlement of liabilities subject to compromise

   $ —       $ 421,774      $ —    

Legal and other professional advisory fees

     (1,732     (19,481      (30,130

Unamortized premiums

     —         —          10,923  

Terminated contracts

     —         —          (55,148

Fresh-start valuation adjustments

     —         (920,699      —    

Other

     —         10,686        1,693  
  

 

 

   

 

 

    

 

 

 
   $ (1,732   $ (507,720    $ (72,662
  

 

 

   

 

 

    

 

 

 

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 may 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 12 months. In February 2018, we closed the 2018 Notes Offering, 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 used the remainder for general corporate purposes.

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 December 31, 2017 our Leverage Ratio and Current Ratio were 2.24 and 1.79, respectively. As of March 31, 2018 our borrowing base was approximately $400 million and we had $393 million available for borrowing under the RBL Facility. At December 31, 2017, we were in compliance with the financial covenants under the RBL Facility. In connection with the 2018 Notes Offering, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. Borrowing base redeterminations become effective on, or about, each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations.

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, 2017 and 2016, our and our predecessor company’s capital expenditures were approximately $73 million, including the predecessor and successor periods, and $26 million, respectively, on an accrual basis excluding acquisitions.

 

79


Table of Contents

We have protected a significant portion of our anticipated cash flows through our commodity hedging program, including through fixed price derivative contracts. As of March 31, 2018, we have hedged crude oil production of approximately 4.7 MMBbls for 2018, 5.0 MMBbls for 2019 and 0.4 MMBbls for 2020.

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 “Business—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)
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended
February 28,
2017
    Year Ended
December 31,
2016
 
           (in thousands)  

Net cash:

      

Provided by (used in) operating activities

   $ 125,551     $ (30,301   $ 12,345  

(Used in) provided by investing activities

     (80,525     (3,133     18,816  

(Used in) provided by financing activities

     (43,170     35,000       (1,701
  

 

 

   

 

 

   

 

 

 

Net (decrease) increase in cash and cash equivalents

   $ 1,856     $ 1,566     $ 29,460  
  

 

 

   

 

 

   

 

 

 

Operating Activities

Cash provided by operating activities increased for the year ended December 31, 2017, including successor and predecessor periods, by $83 million when compared to the same period in 2016, primarily due to the increases in the price of oil and natural gas, and decreases in operating expenses, interest expense and costs incurred in conjunction with our emergence from bankruptcy, partially offset by cash restricted for specific use.

 

80


Table of Contents

Investing Activities

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

 

     Berry Corp.
(Successor)
    Berry LLC
(Predecessor)
 
     Ten Months
Ended
December 31,
2017
    Two Months
Ended
February 28,
2017
     Year Ended
December 31,
2016
 
           (in thousands)  

Capital expenditures (1)

   $ (65,479   $ (3,158    $ (34,796 ) 

Decrease in restricted cash

     —         —          53,418  

Acquisition of properties

     (249,338     —          —    

Proceeds from sale of properties and equipment and other

     234,292       25        194  
  

 

 

   

 

 

    

 

 

 

Cash (used in) provided by investing activities:

   $ (80,525   $ (3,133    $ 18,816  
  

 

 

   

 

 

    

 

 

 

 

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

Cash used in investing activities increased in 2017, including the successor and predecessor periods, by $102 million compared to the year ended December 31, 2016, due to the Hill Acquisition, partially offset by the Hugoton Disposition and the increase in capital expenditures. Capital expenditures increased in 2017, including the successor and predecessor periods, by $34 million, or 97%, compared to the year ended December 31, 2016, 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, improved commodity prices , decreased costs and entry into the RBL Facility.

Financing Activities

Cash used in financing activities was approximately $43 million for the ten months ended December 31, 2017 and was primarily related to repayments of the Emergence Credit Facility and payments of debt issuance costs for the RBL Facility, partially offset by borrowings under 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 year ended December 31, 2016 and was primarily related to repayments of the Pre-Emergence Credit Facility.

Debt

2018 Notes Offering

In February 2018, we closed the 2018 Notes Offering of $400 million in aggregate 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

 

81


Table of Contents

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% 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 the 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

 

    transfer, sell or dispose of 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.

New RBL Facility

On July 31, 2017, Berry LLC, as borrower, entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base, and an initial commitment of $500 million. 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 December 31, 2017, prior to our sale of the 2026 Notes, we had $379 million in borrowings and approximately $21 million in letters of credit outstanding under the RBL Facility. Borrowing base redeterminations become effective on or about each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations. In connection with the 2018 Notes Offering, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of

 

82


Table of Contents

the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. As of March 31, 2018, we had no borrowings and approximately $7 million in letters of credit outstanding and borrowing availability of $393 million under the RBL Facility. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.

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 3.50% per annum, and (ii) a customary base rate plus an applicable margin ranging from 1.50% to 2.50% 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 lenders under the RBL Facility hold a mortgage on 85% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions. The RBL Facility, with certain exceptions, also requires that any future subsidiaries of Berry LLC will also have to grant mortgages, security interests and equity pledges.

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, sell or dispose of assets;

 

    make loans to others;

 

    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 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.

 

83


Table of Contents

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.

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. 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.”

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. On November 13, 2017 the court denied Wells’ motion. Wells filed a notice of appeal on November 27, 2017, but, on February 5, 2018, Wells voluntarily dismissed the appeal against us. As a result, the Bankruptcy Court’s ruling in our favor is final.

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 December 31, 2017 and 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.

We have certain commitments under contracts, including purchase commitments for goods and services. At December 31, 2017, total purchase obligations were approximately $6 million. This largely represents a commitment to invest at least $9 million to extend an existing access road in connection with our Piceance assets, obtain rights to use an existing road 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 2019. If we do not continue to obtain extensions for the road obligation, obtain access to an existing road or construct a new access road, we may trigger the payment obligation that, if we were unable to negotiate a resolution, would reduce our capital available for investment. We also have committed to purchase natural gas for our operations in 2018 that aggregate to approximately $14 million.

 

84


Table of Contents

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 December 31, 2017, we are not aware of material indemnity claims pending or threatened against us.

The following is a summary of our commitments and contractual obligations as of December 31, 2017:

 

     Payments Due  

Contractual Obligations

   Total      2018      2019-2020      2021-2022      2023 and
Beyond
 
     (in thousands)  

Debt obligations:

              

RBL Facility

   $ 379,000      $ —        $ —        $ 379,000      $ —    

Interest(1)

     86,698        18,949        37,898        29,851        —    

Other:

              

Commodity derivatives

     75,281        49,949        25,332        —          —    

Firm natural gas transportation contracts(2)

     9,590        1,751        3,474        3,336        1,029  

Off-Balance Sheet arrangements:

              

Operating lease obligations

     2,750        1,349        1,226        175        —    

Purchase obligations and other(3)

     6,056        56        6,000        —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
   $ 559,375      $ 72,054      $ 73,930      $ 412,362      $ 1,029  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Represents interest on the RBL Facility computed at 4.8% 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, obtain rights to use an existing road 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 2019, If we do not obtain extensions for the road obligation, obtain access to an existing road or construct a new access road, we may trigger the payment obligation which, if we were unable to negotiate a resolution, 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 December 31, 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 December 31, 2017. We did not receive collateral from any of our counterparties. We minimize the credit risk of our 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 Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting

 

85


Table of Contents

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

     245,702  
  

 

 

 

Total post-petition liabilities and allowed claims

     2,137,297  

Reorganization value of assets immediately prior to implementation of the Plan

     (1,722,585
  

 

 

 

Excess post-petition liabilities and allowed claims

   $ 414,712  
  

 

 

 

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 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

 

86


Table of Contents

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. 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

   $ 1,278,527  

Plus: Fair value of non-debt liabilities

     282,511  
  

 

 

 

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.

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.

 

87


Table of Contents

Oil and Natural Gas Properties

Proved Properties

We account for oil and natural gas properties in accordance with the successful efforts method. Under this method, all acquisition 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 in the current period. Gains or losses from the disposal of other properties are recognized in the current period. For assets acquired, we base the capitalized cost on fair value at the acquisition date. We expense expenditures for maintenance and repairs necessary to maintain properties in operating condition, as well as annual lease rentals, as they are incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized over the remaining lives of the related assets. We only capitalized this interest on borrowed funds related to our share of costs associated with qualifying capital expenditures. Interest is capitalized only during the periods in which these assets are brought to their intended use. The amount of capitalized interest and exploratory well costs in 2017 and 2016 was not significant.

We evaluate the impairment of our proved oil and natural gas properties generally on a field by field basis or at the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the expected undiscounted future cash flows are less than net book value. We measure the fair values of proved properties 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 risk-adjusted discount rate. These inputs require significant judgments and estimates by our management at the time of the valuation and are the most sensitive estimates that we make and the most likely to change. The underlying commodity prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes will impact realizable prices.

Impairment of Proved Properties

Based on the analysis described above, for the year ended December 31, 2016, we recorded noncash impairment charges of approximately $1.0 billion associated with proved oil and natural gas properties. The 2016 impairment charges 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 were 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 was attributable to unproved properties. At December 31, 2017 and 2016, the net capitalized costs attributable to unproved properties were approximately $517 million and $680 million, respectively. The unproved amounts were not subject to depreciation, depletion and amortization until they were classified as proved properties and amortized on a unit-of-production basis. We evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the exploration and development work were to be unsuccessful, or management

 

88


Table of Contents

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 December 31, 2017. Based on the analysis described above, for the year ended December 31, 2016, we recorded noncash impairment charges of approximately $13 million associated with unproved oil and natural gas properties. The impairment charges in 2016 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 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 its useful life and the cost of the obligation can be reasonably estimated.

The liability amounts were 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 was initially recorded, we capitalized the cost by increasing the related property, plant and equipment (“PP&E”) balances. If the estimated 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.

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.

 

89


Table of Contents

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 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 assessing 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.

Stock-based Compensation

Subsequent to February 28, 2017, we issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units (“PRSUs”) that vest based on our achievement of certain average prices per share, to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured. We determined the fair value of the RSUs based on an estimate of the fair value of our equity using an income approach. We used a discounted cash flow method to value the estimated future cash flows at an appropriate discount rate. If and when our underlying shares begin trading in the public markets, these estimates will no longer be necessary. For PRSUs, compensation value is measured on the grant date using payout values derived from a Monte-Carlo valuation model. Estimates used in the Monte Carlo valuation model are considered highly complex and subjective. Compensation expense, net of actual forfeitures, for the RSUs and PRSUs is recognized on a straight-line basis over the requisite service periods, which is generally over the awards’ respective three-year vesting or performance periods.

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 August 2017, the Financial Accounting Standards Board (“FASB”) released targeted improvements to hedge accounting standards that will expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company’s risk management activities. These rules are also intended to decrease the cost and complexity of hedge accounting. The new rules are effective for fiscal years beginning after December 15, 2018. We are currently evaluating the impact of the adoption of these new rules.

In May 2017, the 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

 

90


Table of Contents

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 consolidated 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 consolidated 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). The adoption of these rules is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the consolidated 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 do not expect adoption of these rules to have a significant impact on our consolidated 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 consolidated 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 consolidated 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 consolidated 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.

 

91


Table of Contents

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, 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, or 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. The maximum amount of loss due to credit risk that we would incur if the counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was zero at December 31, 2017, as we held no derivative asset positions.

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.

As of December 31, 2017, we had a net derivative liability of $75.3 million carried at fair value, as determined from prices provided by external sources that are not actively quoted. A 10% increase in the index oil and natural gas prices above the December 31, 2017 prices would result in a net liability of approximately $133 million which represents a decrease in the fair value of approximately $57 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2017 prices, would result in a net liability of approximately $18 million, which represents an increase in the fair value of approximately $57 million. 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

 

92


Table of Contents

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 December 31, 2017, we had debt outstanding under the RBL Facility of approximately $379 million, which incurred interest at floating rates. As of December 31, 2017, 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 the RBL Facility in February 2018. As of March 31, 2018, we had no amount outstanding under the 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.

 

93


Table of Contents

BUSINESS

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. 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:

 

    high oil content, which makes up approximately 79% of our production;

 

    favorable Brent-influenced crude oil pricing dynamics;

 

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

 

    stable and predictable development and production cost structures;

 

             years of low-risk identified development drilling opportunities with attractive full-cycle economics; and

 

    potential in-basin strategic opportunities to expand our existing inventory with new locations of substantially similar geology and economics.

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 for PUD wells drilled and completed in California will average less than $450,000 per well.

We also maintain 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.

 

94


Table of Contents

As of December 31, 2017, we had estimated total proved reserves of 141,385 MBoe, of which approximately 66% were located in California and 57% were proved developed producing reserves. For the three months ended December 31, 2017, we had average production of approximately 27.9 MBoe/d, of which approximately 79% 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 reserve report, which is attached as Annex A. Our 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 in 2018 approximately $70 million to $80 million of our capital budget will be sufficient to maintain production volumes consistent with those achieved in 2017.

Our Oil-Weighted, High Margin Production

Our high oil content combined with a Brent-influenced California pricing dynamic and attractive cost structure has resulted in strong operating margins.

We expect our PUD reserves to have lower operating expenses per Boe than our PDP reserves due to the higher rates of production associated with new wells compared to existing producing wells (which have been producing for an average of 11 years). The lower expected operating expenses of our PUDs also support attractive breakeven commodity prices all-in (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.

 

95


Table of Contents

The following chart represents our average operating expenses per Boe over the next five years as provided to our reserve engineers in connection with the preparation of our December 31, 2017 reserve report.

PUD / PDP Operating Expenses (Avg. for 2018-2022) ($/Boe)(1)(2)

 

LOGO

 

(1) Expected operating expenses, as estimated by our management and provided to our reserve engineers in connection with the preparation of our reserve report as of December 31, 2017, associated with (i) our PUDs as of December 31, 2017 are $11.1 million, $37.4 million, $61.8 million, $64.1 million and $60.1 million for 2018, 2019, 2020, 2021 and 2022, respectively, and (ii) our PDP reserves as of December 31, 2017 are $161.9 million, $144.0 million, $128.3 million, $114.0 million and $103.8 million for 2018, 2019, 2020, 2021 and 2022, respectively.
(2) Expected aggregate production associated with (i) our PUDs as of December 31, 2017 are 689,519 Boe, 3,075,502 Boe, 5,001,175 Boe, 5,527,523 Boe and 5,050,158 Boe for 2018, 2019, 2020, 2021 and 2022, respectively, and (ii) our PDP reserves as of December 31, 2017 are 9,350,473 Boe, 8,006,566 Boe, 6,944,450 Boe, 6,050,161 Boe and 5,352,475 Boe for 2018, 2019, 2020, 2021 and 2022, respectively. Our expected PUD production over the next five years reflects the aggregation of the expected individual production profiles of each of our 790 gross (786 net) PUD drilling locations as of December 31, 2017 over the next five years based on each location’s expected completion date and our five-year development plan. Our expected PDP production over the next five years reflects the aggregation of the expected individual production profiles of each of our producing wells as of December 31, 2017 over the next five years.

Operating expenses include lease operating expenses, electricity generation expenses, transportation expenses and marketing expenses, net of electricity sales and marketing revenue. 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 further 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.”

Our Attractive Development Opportunities

We expect our identified drilling locations to generate attractive rates of return. For example, we expect the single-well rates of returns on our drilling opportunities associated with our PUD reserves to average approximately 45%, based on the assumptions used in preparing our December 31, 2017 reserve report, including pricing and cost assumptions, which can be found under “Primary Economic Assumptions” on page 6 of our reserve report.

Our estimated development costs associated with our PUD reserves are $8.89 per Boe. When combined with our anticipated PUD operating expenses for the next five years of $12.12 per Boe, we believe our identified development opportunities present attractive break-even economics.

 

96


Table of Contents

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 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.

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. PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “Prospectus Summary—Summary Reserves and Operating Data—PV-10.”

The charts below summarize certain characteristics of our proved reserves and PV-10 of proved reserves as of December 31, 2017 (as described in the table below and in “Prospectus Summary—Summary Reserves and Operating Data”):

 

1P Reserves by Category (141 MMBoe)

 

LOGO

  

1P Reserves by Commodity (141 MMBoe)

 

LOGO

1P Reserves by Area (141 MMBoe)

 

        LOGO

  

1P PV-10 by Area ($1.1 billion)

 

LOGO    

 

97


Table of Contents

The table below summarizes our proved reserves and PV-10 by category as of December 31, 2017:

 

     Oil
(MMBbl)
     Natural
Gas
(Bcf)
     NGLs
(MMBbl)
     Total
(MMBoe)
     % of
Proved
     % Proved
Developed
     Capex(2)
($MM)
     PV-10(3)
($MM)
 

PDP(1)

     63        100        1        81        57        93      $ 50      $ 762  

PDNP(1)

     6        —          —          6        4        7        10        89  

PUDs(1)

     32        137        —          55        39        —          488        262  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total(1)

     101        237        1        141        100        100      $ 548      $ 1,114  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(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 $54.42 per Bbl ICE (Brent) for oil and NGLs and $2.98 per MMBtu NYMEX Henry Hub for natural gas at December 31, 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 December 31, 2017.
(3) PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “Prospectus Summary—Summary Reserves and Operating Data—PV-10.” PV-10 does not give effect to derivatives transactions.

The table below summarizes our average net daily production by basin for the three months ended December 31, 2017:

 

     Average Net Daily
Production for the Three Months
Ended December 31, 2017
 
     (MBoe/d)      Oil (%)  

California

     19.5        100

Uinta basin

     5.3        48

Piceance basin

     2.2        2

East Texas basin

     0.9        —    
  

 

 

    

Total

     27.9        79
  

 

 

    

 

LOGO

Our Development Inventory

We have an extensive inventory of low-risk, high-return development opportunities. In addition to our approximately 790 gross (786 net) identified drilling locations associated with proved undeveloped

 

98


Table of Contents

reserves as of December 31, 2017, we also have identified approximately 1,300 gross (1,300 net) additional drilling locations with economics that management believes are similar to those of our proved undeveloped locations. Further, we have identified an additional 3,800 gross (3,500 net) drilling locations with economics that are currently under review. 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 December 31, 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 approximately 790 gross (786 net) locations associated with PUDs as of December 31, 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.
(4) Represents our weighted average working interest in our active wells.
(5) Represents our weighted average net revenue interest for the month of December 2017.

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 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.

 

99


Table of Contents

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 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 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. 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 structure and low-risk developmental drilling opportunities with predictable production profiles. The nature of our assets provides us with 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 proved undeveloped reserves are projected to average single-well rates of return of approximately 45%, based on the assumptions used in preparing our December 31, 2017 reserve report, including pricing and cost assumptions, which can be found under “Primary Economic Assumptions” on page 6 of our reserve report. We also have identified approximately 1,300 gross (1,300 net) additional drilling locations with economics that management believes are similar to those of our proved undeveloped locations and another 3,800 additional identified drilling locations that are currently under review.

 

    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.

 

    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 levered free cash flows as well as the value of our production and reserves. In doing so, we 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.

 

   

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

 

100


Table of Contents
 

enhancements and marketing of production. We expect our operations to continue to generate sufficient levered free cash flow at current commodity prices to fund maintenance, operations and growth. Also, unlike our peers who operate primarily in unconventional plays, our assets generally do not necessitate inventory-constrained and highly specialized equipment, which provides us relative insulation from cost inflation pressures. Our high degree of operational control and relatively stable cost environment provide us significant visibility and understanding of our expected cash flows.

 

    Conservative balance sheet leverage with ample liquidity and minimal contractual obligations. In February 2018, we closed the 2018 Notes Offering, which resulted in net proceeds to us of approximately $392 million after deducting expenses and the initial purchasers’ discount. After giving effect to our sale of common stock in this offering, we expect to have approximately $             million of available liquidity, defined as cash on hand plus availability under the 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.

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 levered free 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 proppantless slick water fracture stimulation techniques. In addition, we intend to take advantage of underdevelopment in basins where we operate by expanding our geologic investigation of deeper reservoirs on our acreage and adjacent acreage below existing producing reservoirs. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs.

 

    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.

 

101


Table of Contents
    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.

 

    Return excess free cash flow to stockholders. Our objective is to implement a disciplined and returns-focused approach to capital allocation in order to generate excess free cash flow. We intend to return portions of that excess free cash flow to stockholders on a quarterly basis. For a discussion of our dividend policy, please see “Dividend Policy.”

 

    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. We will review our hedging program continuously as conditions change.

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 92% over our 2017 capital expenditures, including the successor and predecessor periods, of approximately $73 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 exclusively 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 drilling opportunities in Colorado and Utah 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 consistent 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

 

102


Table of Contents

us the ability to hedge a material amount of our future expected production. The chart below summarizes our derivative contracts in place as of March 31, 2018.

Hedge Volumes in MMBbls (MBbl/d)

 

LOGO

 

(1) Calculations based on 275 days as of March 31, 2018.

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 and has been one of the most productive oil and natural gas regions in the world.

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 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

 

103


Table of Contents

the remaining approximately 84% working interest in the third quarter of 2017; (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