DRS 1 filename1.htm Document
As confidentially submitted to the Securities and Exchange Commission on November 16, 2018
Registration No. 333-      .

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
 
Confidential Draft Submission No. 1
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
Berry Petroleum Corporation
(Exact Name of Registrant as Specified in its Charter)
Delaware
1311
81-5410470
(State or other Jurisdiction of
Incorporation or Organization)
(Primary Standard Industrial
Classification Code Number)
(IRS Employer
Identification Number)
16000 N. Dallas Parkway, Suite 500, Dallas, Texas 75248
(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
16000 N. Dallas Parkway, Suite 500, Dallas, Texas 75248

(661) 616-3900
(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)
 
Copies to:
Douglas E. McWilliams
Sarah K. Morgan
Vinson & Elkins L.L.P.
1001 Fannin, Suite 2500
Houston, Texas 77002-6760
(713) 758-2222
Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.
 
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ý
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. o
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. o
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. o
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 o
Accelerated filer o
Non-accelerated filer ý
Smaller reporting company o
 
Emerging growth company ý
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. o
 
CALCULATION OF REGISTRATION FEE
Title of Each Class of Securities to be Registered
Amount to be Registered(1)
Proposed Maximum Offering Price Per Share(2)
Proposed Maximum Offering Price(2)
Amount of Registration Fee(3)
Common Stock, par value $0.001 per share
61,448,234
$
$
$
(1)
Pursuant to Rule 416(a) under the Securities Act of 1933, as amended (the “Securities Act”), this registration statement shall be deemed to cover any additional shares of common stock that may be offered or issued in connection with any stock split, stock dividend or similar transaction.
(2)
Estimated solely for the purpose of calculating the registration fee pursuant to rule 457(c) under the Securities Act, as amended, on the basis of the average of the high and low prices of the Registrant’s common stock as reported on the NASDAQ Stock Market on           , 2018.
(3)
To be paid in connection with the initial filing of the registration statement.

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



The information in this prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state or jurisdiction where the offer or sale is not permitted.
Subject to Completion, dated  , 2018

61,448,234 Shares
berrypetroleumcorpora_image1.jpg
Common Stock
 
This prospectus covers the offer and sale of up to 61,448,234 shares of our common stock by the selling stockholders identified in this prospectus, or their permitted transferees.
Pursuant to this prospectus, the selling stockholders, or permitted transferees, may offer and sell the shares of common stock from time to time, as they may determine, through public or private transactions or through other means described in “Plan of Distribution” and at the prices and terms that will be determined by the then-prevailing market prices or at privately negotiated prices, directly or through a broker or brokers, who may act as agent or as principal or by a combination of such methods of sale. For additional information of the methods of sale, you should refer to the section entitled “Plan of Distribution” beginning on page 172. We will not receive any of the proceeds from the sale of the shares by the selling stockholders. We will bear all costs, expenses and fees in connection with the registration of the shares. The selling stockholders will bear all commissions, fees and discounts, if any, attributable to the sale of the shares.
This prospectus describes the general terms of the securities and the general manner in which the selling stockholders will offer the securities. The specific terms of any offering of the securities may be included in a supplement to this prospectus. The prospectus supplement may describe the specific manner in which the selling stockholders will offer the securities and may also add, update or change information contained in this prospectus. You should read this prospectus and any accompanying prospectus supplement carefully before you make your investment decision.
Our common stock is listed on the Nasdaq Global Select Market (the “NASDAQ”) under the symbol “BRY.” The closing price of our common stock on November 15, 2018 was $13.10 per share.
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 25 of this prospectus.
 
Neither the Securities and Exchange Commission (“SEC”) 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.
 

The date of this prospectus is            , 2018




TABLE OF CONTENTS
 
Neither we nor the selling stockholders have authorized anyone to provide you with information different from that contained in this prospectus, any prospectus supplement 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. The selling stockholders 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.”
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” or, prior to February 28, 2017, our "predecessor company"). On May 11, 2016, our predecessor company filed petitions for reorganization in the U.S. Bankruptcy Court (the “Bankruptcy Court”) for the Southern District of Texas (collectively, the “Chapter 11 Proceedings”) . 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. In anticipation of emergence, Berry Petroleum Corporation (“Berry Corp.”) was formed

i




for the purpose of having all the membership interests of Berry LLC assigned to it upon Berry LLC’s emergence from bankruptcy. On January 27, 2017, the Bankruptcy Court approved and confirmed the Plan. On February 28, 2017 (the “Effective Date”), the Plan became effective and was implemented, including the emergence of Berry LLC from bankruptcy as a wholly-owned subsidiary of Berry Corp., separate from the Linn Entities. A final decree closing the Chapter 11 Proceeding was entered September 28, 2018, with the Court retaining jurisdiction as described in the confirmation order and without prejudice to the request of any party-in-interest to reopen the case including with respect to certain, immaterial remaining matters.
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 nor the selling stockholders have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.
TRADEMARKS AND TRADE NAMES
We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.


ii




PROSPECTUS SUMMARY
This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the information under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes to those financial statements appearing elsewhere in this prospectus. You should read “Risk Factors” for information about important risks that you should consider carefully before investing in our common stock.
Except as noted or as the context requires otherwise, when we use the terms “we,” “us,” “our,” the “Company,” or similar words in this prospectus, (i) on or prior to the Effective Date, we are referring to Berry LLC, and (ii) following the Effective Date, we are referring to Berry Corp. and its subsidiary, Berry LLC, as applicable. When we refer to “our predecessor company,” we are referring to Berry LLC as it existed on or prior to the Effective Date. This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in “Annex B: Glossary of Oil and Natural Gas Terms.”
Our Company
We are a California-based independent upstream energy company engaged primarily in the development and production of conventional oil reserves located onshore in the western United States. Our long-lived, predictable and high margin asset base is uniquely positioned to support our objectives of generating top-tier corporate-level returns and positive free cash flow through commodity price cycles. We believe that executing our strategy across our low-declining production base and extensive inventory of identified drilling locations will result in long-term, capital efficient production growth as well as the ability to return excess free cash flow to stockholders.
We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin of California and the Uinta basin of Utah, and, to a lesser extent, the low geologic risk natural gas resource play in the Piceance basin in Colorado. In the aggregate, the Company’s assets are characterized by:
high oil content, which makes up more than 80% 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;
a large inventory of low-risk identified development drilling opportunities with attractive full-cycle economics; and
potential in-basin organic and 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. In contrast, we estimate the cost of PUD wells drilled and completed in the Piceance basin will average $1.8 million per well. Using SEC Pricing as of December 31, 2017, there were approximately 80 gross PUD locations associated with projects in the Piceance basin. Subsequent

1




to year end, as a result of increasingly negative local gas pricing differentials, we revised our current development plan to exclude these Piceance locations.
We own additional 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. On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin. We anticipate closing this sale in the fourth quarter of 2018.
Using SEC Pricing as of December 31, 2017, we had estimated total proved reserves of 141,384 MBoe. For the three months ended September 30, 2018, we had average production of approximately 27.4 MBoe/d, of which approximately 81% was oil. In California, our average production for the three months ended September 30, 2018 was 19.5 MBoe/d, of which approximately 100% was oil.
The Berry Advantage
We believe that our combination of low production decline rates, high margin oil-weighted production, attractive development opportunities and a stable cost environment differentiates us from our competitors and provides for low-breakeven commodity prices and an ability to generate top-tier corporate level returns, positive levered free cash flow and capital-efficient growth through commodity price cycles.
Our Low Declining Production Base
Our reserves are generally long-lived and characterized by relatively low production decline rates, affording us significant capital flexibility and an ability to efficiently hedge material quantities of future expected production. For example, our PDP reserves have an estimated annual decline rate of approximately 14% to 12% in the years between 2018 and 2022 based on total PDP Boe reserves as of December 31, 2017 as reflected in our SEC reserve report, which is attached as Annex A. Our SEC reserve report is based on the estimated individual well production profiles used to determine our PDP reserves. Based on the assumptions underlying our PUD estimates, we estimate that we will require approximately $10 per Boe in annual capital expenses to keep production volumes consistent each year over the next three years.
Our Oil-Weighted, High Margin Production
Our highly oil-weighted production combined with a Brent-influenced California pricing dynamic and stable cost structures has resulted, and is expected to continue to result, in strong operating margins. As of December 31, 2017, our California PUD reserves were 100% oil.
Our Attractive Development Opportunities
Our estimated development costs associated with our PUD reserves are $8.89 per Boe on a total company basis and $10.95 per Boe in California. We believe that our estimated development costs, when combined with our operating costs, commodity mix and price realizations, present attractive breakeven economics for our development opportunities.
We expect our identified drilling locations to generate attractive rates of return. The following table presents our expected average single-well rates of return on drilling opportunities associated with our California PUD reserves based on the assumptions used in preparing our December 31, 2017 SEC reserve report, including pricing and cost assumptions, which can be found under “Primary Economic Assumptions” on page 6 of our reserve report. Using SEC Pricing as of December 31, 2017, there were approximately 23 MMBoe of PUDs associated with projects in the Piceance basin. Subsequent to year end, as a result of increasingly negative local gas pricing differentials, we revised our current development plan to exclude development in the Piceance basin. As a result, information with respect to our Colorado

2




PUDs as of December 31, 2017 has been omitted from the table below. The table also includes a commodity price sensitivity scenario, which is based on Strip Pricing as of May 31, 2018.
 
PUD Weighted-Average Economics
 
Per Well
 
IRR
Asset
EUR
(MBOE)
 
D&C
($ in thousands)
 
SEC Pricing as of December 31, 2017(1)
 
Strip Pricing as of May 31,
2018(2)
California
45
 
<$450
 
37%
 
73%
__________
(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 Intercontinental Exchange ("ICE") Brent oil (“Brent”) for oil and NGLs and $2.98 per MMBtu New York Mercantile Exchange (“NYMEX”) Henry Hub ("HH") for natural gas at December 31, 2017. The volume-weighted average prices over the lives of the properties were $48.20 per barrel of oil and condensate, $28.25 per barrel of NGL and $2.935 per thousand cubic feet of gas. The prices were held constant for the lives of the properties, and we took into account pricing differentials reflective of the market environment. 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)
Our Strip Pricing reserves were prepared on the same basis as our SEC reserves and do not include changes to costs, other economic parameters, well performance or drilling activity subsequent to December 31, 2017, except for the use of pricing based on closing month futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX (HH) for natural gas on May 31, 2018 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Our Strip Pricing oil, natural gas and NGL reserves were determined using index prices for natural gas and oil, respectively, as of May 31, 2018 without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our Strip Pricing reserves were $74.59 per Bbl for oil and NGLs for 2018, $72.98 for 2019, $69.15 for 2020 and $66.49 for 2021 thereafter, on the ICE (Brent), and $2.94 per MMBtu for natural gas for 2018, $2.75 for 2019, $2.68 for 2020 and $2.66 for 2021 thereafter, on the NYMEX (HH). The volume-weighted average prices over the lives of the properties were $61.67 per barrel of oil and condensate, $19.49 per barrel of NGL, and $1.943 per thousand cubic feet of gas. We have taken into account pricing differentials reflective of the market environment, and NGL pricing used in determining our Strip Pricing reserves was approximately ICE (Brent) for oil less $49.00. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. Strip Pricing futures prices are not necessarily an accurate projection of future oil and gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves. Please see “—Summary Reserves and Operating Data.”

Our Stable California Operating and Development Cost Environment
The operating and development cost structures of our conventional California asset base are inherently stable and predictable. Our California focus largely insulates us from the cost inflation pressures experienced by our peers who operate primarily in unconventional plays. This is the result of our established infrastructure, low-intensity service requirements and lack of dependence on inventory-constrained and often highly specialized equipment. In addition, the majority of our California assets reside in the shallow steam-flood fields of the San Joaquin basin, which are lower cost to develop compared to the water flood fields of the Los Angeles and Ventura basins.
Our Reserves and Assets
The majority of our reserves are composed of heavy crude oil in shallow, long-lived reservoirs. Approximately two-thirds of our proved reserves and approximately 90% of the PV-10 value of our proved reserves are derived from our assets in California. We also operate in the Uinta basin in Utah, a stacked, multi-bench, light-oil-prone play with significant undeveloped resources and in the East Texas basin, an extensive over-pressured natural gas cell, as well as in the Piceance basin in Colorado, a prolific natural gas play with low geologic risk. On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin. We anticipate closing this sale in the fourth quarter of 2018.
Using SEC Pricing as of December 31, 2017, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our proved reserves were approximately $1.0 billion and $1.1 billion, respectively. Using Strip Pricing as of May 31, 2018, the PV-10 of our proved reserves was approximately $1.9 billion. PV-10 is a financial measure that is not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”).

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For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—Summary Reserves and Operating Data—PV-10.”
The charts below summarize certain characteristics of our proved reserves and PV-10 of proved reserves using SEC Pricing as of December 31, 2017 and Strip Pricing as of May 31, 2018 (as described in the tables below and in “—Summary Reserves and Operating Data”):
berrypetroleumcorpora_image2.gif
The tables below summarize our proved reserves and PV-10 by category using SEC Pricing as of December 31, 2017 and Strip Pricing as of May 31, 2018:
 
SEC Pricing as of December 31, 2017(1)
 
Oil (MMBbl)
 
Natural Gas (Bcf)
 
NGLs (MMBbl)
 
Total (MMBoe)
 
% of Proved
 
% Proved Developed
 
Capex(2) ($MM)
 
PV-10(3) ($MM)
PDP
63

 
100

 
1

 
81

 
57
%
 
93
%
 
$
50

 
$
762

PDNP
6

 

 

 
6

 
4
%
 
7
%
 
10

 
89

PUD(5)
32

 
137

 

 
55

 
39
%
 
%
 
488

 
262

Total
101

 
237

 
1

 
141

 
100
%
 
100
%
 
$
548

 
$
1,114

 
Strip Pricing as of May 31, 2018(4)
 
Oil (MMBbl)
 
Natural Gas (Bcf)
 
NGLs (MMBbl)
 
Total (MMBoe)
 
% of Proved
 
% Proved Developed
 
Capex(2) ($MM)
 
PV-10(3) ($MM)
PDP
64

 
67

 
1

 
77

 
67
%
 
93
%
 
$
50

 
$
1,205

PDNP
6

 

 

 
6

 
5
%
 
7
%
 
10

 
136

PUD
32

 

 

 
32

 
28
%
 
%
 
348

 
521

Total
102

 
67

 
1

 
115

 
100
%
 
100
%
 
$
407

 
$
1,862


4




__________
(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 (HH) for natural gas at December 31, 2017. The volume-weighted average prices over the lives of the properties were $48.20 per barrel of oil and condensate, $28.25 per barrel of NGL and $2.935 per thousand cubic feet of gas. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. 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.
(4)
Our Strip Pricing reserves were prepared on the same basis as our SEC reserves and do not include changes to costs, other economic parameters, well performance or drilling activity subsequent to December 31, 2017, except for the use of pricing based on closing month futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX (HH) for natural gas on May 31, 2018 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Our Strip Pricing oil, natural gas and NGL reserves were determined using index prices for natural gas and oil, respectively, as of May 31, 2018 without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our Strip Pricing reserves were $74.59 per Bbl for oil and NGLs for 2018, $72.98 for 2019, $69.15 for 2020 and $66.49 for 2021 thereafter, on the ICE (Brent), and $2.94 per MMBtu for natural gas for 2018, $2.75 for 2019, $2.68 for 2020 and $2.66 for 2021 thereafter, on the NYMEX (HH). The volume-weighted average prices over the lives of the properties were $61.67 per barrel of oil and condensate, $19.49 per barrel of NGL, and $1.943 per thousand cubic feet of gas. We have taken into account pricing differentials reflective of the market environment, and NGL pricing used in determining our Strip Pricing reserves was approximately ICE (Brent) for oil less $49.00. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. Strip Pricing futures prices are not necessarily an accurate projection of future oil and gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves. The decrease in reserve volumes using Strip Pricing as opposed to SEC Pricing is primarily the result of lower realized gas prices in Colorado using Strip Pricing as of May 31, 2018. Please see “—Summary Reserves and Operating Data.”
(5)
Using SEC Pricing as of December 31, 2017, there were approximately 23 MMBoe of PUDs associated with projects in the Piceance basin. Subsequent to year end, as a result of increasingly negative local gas pricing differentials, we revised our current development plan to exclude the development in the Piceance basin.

The table below summarizes our average net daily production by basin for the three months ended September 30, 2018:
 
Average Net Daily Production(1)        for the Three Months Ended September 30, 2018
 
(MBoe/d)
 
Oil (%)
California
19.5

 
100
%
Uinta basin
5.1

 
54
%
Piceance basin
2.0

 
1
%
East Texas basin(2)
0.7

 
1
%
Total
27.4

 
81
%
__________
(1)
Production represents volumes sold during the period.
(2)
On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin. We anticipate closing this sale in the fourth quarter of 2018.

Our Development Inventory
We have an extensive inventory of low-risk, high-return development opportunities. As of September 30, 2018, we identified 3,386 gross drilling locations that we anticipate drilling over the next 5 to 10 years, which we refer to as our “Tier 1” locations, and 3,799 additional gross drilling locations that are currently under review. For a discussion of how we identify drilling locations, please see “Business—Our Reserves and Production Information—Determination of Identified Drilling Locations.”

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We operate over 95% of our productive wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, approximately 75% of our acreage is held by production, including 99% of our acreage in California. Our high degree of operational control, together with the large portion of our acreage that is held by production, gives us flexibility over the execution of our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production.
The following table summarizes certain information concerning our operations as of September 30, 2018:
 
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
10,926

 
8,015

 
99
%
 
2,563

 
99
%
 
94
%
 
4,991

 
4,983

Uinta basin
130,677

 
95,912

 
72
%
 
935

 
95
%
 
78
%
 
1,244

 
1,083

Piceance basin
10,533

 
8,008

 
85
%
 
170

 
72
%
 
63
%
 
870

 
664

East Texas basin(6)
5,853

 
4,533

 
100
%
 
116

 
99
%
 
74
%
 
80

 
79

Total
157,989

 
116,468

 
75
%
 
3,668

 
97
%
 
88
%
 
7,185

 
6,809

__________
(1)
Includes 486 steamflood and waterflood injection wells in California.
(2)
Excludes 91 wells in the Piceance basin each with a 5% 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 “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 nine months ended September 30, 2018.
(6)
On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin. We anticipate closing this sale in the fourth quarter of 2018.


Additionally, our California assets are primarily focused on the Hill Diatomite, Thermal Diatomite and Thermal Sandstones development areas. As set forth in the table below, as of September 30, 2018, we identified 3,386 Tier 1 gross drilling locations and 3,799 additional gross drilling locations that are currently under review associated with these assets.
 
 
 
 
 
 
 
 
 
 
Gross Drilling Locations(1)
State
 
Project Type
 
Well Type
 
Completion Type
 
Recovery Mechanism
 
Tier 1(2)
 
Additional
 
Total
California
 
Hill Diatomite (non-thermal)
 
Vertical
 
Low intensity pin point fracture
 
Pressure depletion augmented with water injection
 
285

 
585

 
870

California
 
Thermal Diatomite
 
Vertical
 
Short interval perforations
 
Cyclic steam injection
 
795

 
979

 
1,774

California
 
Thermal Sandstones
 
Vertical / Horizontal
 
Perforation/Slotted liner/gravel pack
 
Continuous and cyclic steam injection
 
1,855

 
492

 
2,347

Utah
 
Uinta
 
Vertical / Horizontal
 
Low intensity fracture stimulation
 
Pressure depletion
 
451

 
793

 
1,244

Colorado(3)
 
Piceance
 
Vertical
 
Proppantless slick water fracture stimulation
 
Pressure depletion
 

 
870

 
870

Texas(4)
 
East Texas
 
Vertical/Horizontal
 
Low intensity fracture stimulation
 
Pressure depletion
 

 
80

 
80

Total
 
 
 
 
 
 
 
 
 
3,386

 
3,799

 
7,185

__________
(1)
We had 790 gross (786 net) locations associated with PUDs as of December 31, 2017 using SEC Pricing, including 161 gross (161 net) steamflood and waterflood injection wells. Of those 790 gross PUD locations, 710 are associated with projects in California and 80 are associated with the Piceance basin. Please see “Business—Our Reserves and Production Information—Determination of Identified Drilling Locations”

6




for more information regarding the process and criteria through which we identified our drilling locations. During the nine months ended September 30, 2018, we drilled 86 gross (86 net) wells that were associated with PUDs at December 31, 2017, including 25 gross (25 net) steamflood and waterflood injection wells.
(2)
Represents wells that we anticipate drilling over the next 5 to 10 years.
(3)
Using SEC Pricing as of December 31, 2017, there were 80 gross PUD locations associated with projects in the Piceance basin. Subsequent to year end, as a result of increasingly negative local gas pricing differentials, we revised our current development plan to exclude these Piceance locations.
(4)
On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin. We anticipate closing this sale in the fourth quarter of 2018.

Other Assets
We produce oil from heavy crude reservoirs using steam to heat the oil so that it will flow. To assist in this development, we own and operate five natural gas cogeneration plants that produce steam. These plants supply approximately 23% of our steam needs and approximately 43% of our field electricity needs in California at a discount to electricity market prices. To further offset our costs, we currently also sell surplus power produced by three of our cogeneration facilities under long-term contracts with California utility companies.
In addition, we own gathering, treatment and storage facilities in California that currently have excess capacity, reducing our need to spend capital to develop nearby assets and generally allowing us to control certain operating costs. We also own a network of oil and gas gathering lines across our assets outside of California, and our oil and natural gas is transported through such lines and third-party gathering systems and pipelines.
We also own a natural gas processing plant with capacity of approximately 30 MMcf/d in the Brundage Canyon area, located in Duchesne County, Utah. This facility takes delivery from gathering and compression facilities we operate. Approximately 90% of the gas gathered at these facilities is produced from wells that we operate. Current throughput at the processing plant is 16-18 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 in California are projected to average single-well rates of return of approximately 37%, assuming SEC Pricing as of December 31, 2017, based on the assumptions used in preparing our SEC reserve report, which can be found under “Primary Economic Assumptions” on page 6 of our reserve report, and 73% assuming Strip Pricing as of May 31, 2018, based on the assumptions found in the Strip Pricing addendum to our reserve report. Our extensive inventory consists of 3,386 Tier 1 gross drilling locations and 3,799 additional gross 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 West Texas Intermediate oil ("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.

7




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 75% 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 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 $391 million after deducting expenses and the initial purchasers’ discount. As of September 30, 2018, we have $417 million of available liquidity, defined as cash on hand plus availability under the $1.5 billion reserves-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.
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.

8




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. If commodity prices increase for a sustained period of time, we would consider repaying debt obligations or returning additional capital to shareholders. 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 into 2020 as part of our crude oil hedging program. We will review our hedging program continuously as conditions change.
Recent Developments
Initial Public Offering and Series A Preferred Stock Conversion.
In July 2018, we completed the initial public offering of our common stock (the "IPO"), and as a result, on July 26, 2018, our common stock began trading on the NASDAQ Global Select Market under the ticker symbol BRY. We received approximately $111 million of net proceeds, after deducting underwriting discounts and offering expenses payable by us, for the 8,695,653 shares of common stock issued for our benefit in the IPO, net of the shares sold for the benefit of certain selling stockholders. The price to the public for the shares sold in our IPO was $14.00 per share.
Of the approximately $111 million of net proceeds we received in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility, which included $60 million we borrowed to make the payment due to the holders of our Series A Preferred Stock in connection with the conversion of preferred stock to common stock. We used the remainder for general corporate purposes.
In connection with the IPO, on July 17, 2018, we entered into stock purchase agreements with certain funds affiliated with Oaktree Capital Management and Benefit Street Partners, pursuant to which we purchased an aggregate of 410,229 and 1,391,967 shares of our common stock, respectively, or 1,802,196 in total. In addition to the 8,695,653 shares of common stock issued and sold for our benefit in the IPO, we simultaneously received $24 million for issuing and selling 1,802,196 shares to the public and paid $24 million to purchase 1,802,196 shares under the stock purchase agreements. We purchased the shares immediately following the closing of the IPO and retired and returned them to the status of authorized but unissued shares.
The selling shareholders sold an additional 2,545,630 shares at a price to the public of $14.00 per share for which we did not receive any proceeds.
In connection with the IPO, each of the 37.7 million shares of our Series A Convertible Preferred Stock, par value $0.001 per share (the “Series A Preferred Stock”), was automatically converted into 1.05 shares of our common stock,

9




or 39.6 million shares in aggregate, and the right to receive a cash payment of $1.75 (the "Series A Preferred Stock Conversion"). The cash payment was reduced in respect of any cash dividend paid by the Company on such share of Series A Preferred Stock for any period commencing on or after April 1, 2018. Because we paid the second quarter preferred dividend of $0.15 per share in June, the cash payment for the conversion was reduced to $1.60 per share, or approximately $60 million. The additional 1.9 million shares of common stock (the aggregate conversion premium of 0.05 common share per 1 share of Series A Preferred Stock outstanding) received by the preferred stockholders in the conversion were assigned a value of $14.00 per share in the IPO.
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 25 for an explanation of these risks before investing in our common stock and “Cautionary Note Regarding Forward-Looking Statements” on page 42 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 and directly affect our results.
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.
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.

10




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. On May 11, 2016 our predecessor company filed bankruptcy. The 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 (the "Chapter 11 Proceeding"). On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding (the "Plan"). On February 28, 2017, the Effective Date occurred and the Plan became effective and was implemented. A final decree closing the Chapter 11 Proceeding was entered September 28, 2018, with the Court retaining jurisdiction as described in the confirmation order and without prejudice to the request of any party-in-interest to reopen the case including with respect to certain, immaterial remaining matters.
Today, we foster Mr. Berry’s entrepreneurial spirit and leadership skills. We encourage our teams to apply his business ethos at every level to move us forward. We strive to have a positive presence in the communities surrounding our operations. Our employees belong to the communities where they work, which we believe aligns our interests with those of the people who live near our operations.
Emerging Growth Company Status
We are an “emerging growth company” as such term is used in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies, we will not be required to:
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;

11




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 Our Capital Stock—We are an “emerging growth company,” and will be able take advantage of reduced disclosure requirements applicable to “emerging growth companies,” which could make our common stock less attractive to investors.”
Corporate Information
We were incorporated in Delaware in February 2017. We have executive offices located at 5201 Truxtun Ave., Bakersfield, California 93309 and at 16000 N. Dallas Pkwy, Ste 500, Dallas, Texas 75248, where we have our principal executive offices. 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.

12




THE OFFERING
Common stock that may be offered by the selling stockholders
61,448,234 shares.
 
 
Common stock outstanding prior to and after this offering
81,642,953 shares
 
 
Use of proceeds
We will not receive any proceeds from the sale of shares of our common stock by the selling stockholders pursuant to this prospectus.
 
 
Dividend policy
Please see “Dividend Policy.”
 
 
Listing and trading symbol
Our common stock trades on the NASDAQ under the symbol “BRY.”
 
 
Risk factors
You should carefully read and consider the information set forth under the heading “Risk Factors” on page 25 of this prospectus and all other information set forth in this prospectus before deciding to invest in our common stock.

13




SUMMARY HISTORICAL AND PRO FORMA FINANCIAL INFORMATION
The following table shows the summary historical financial information, for the periods and as of the dates indicated, of our predecessor company (Berry LLC) and successor company (Berry Corp.). The summary historical financial information as of and for the year ended December 31, 2016 is derived from the audited historical financial statements of Berry LLC included elsewhere in this prospectus. The summary historical financial information as of and for the two months ended February 28, 2017 is derived from audited financial statements of Berry LLC included elsewhere in this prospectus. The summary historical financial information for the ten months ended December 31, 2017 is derived from audited consolidated financial statements of Berry Corp. included elsewhere in this prospectus. The summary historical financial information as of and for the seven months ended September 30, 2017 and as of and for the nine months ended September 30, 2018 is derived from unaudited consolidated financial statements of Berry Corp. included elsewhere in this prospectus.
Upon Berry LLC’s emergence from bankruptcy on February 28, 2017, or the Effective Date, in connection with the Plan, Berry LLC adopted fresh-start accounting and was recapitalized, which resulted in Berry LLC becoming a wholly-owned subsidiary of Berry Corp. and Berry Corp. being treated as the new entity for financial reporting. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. These fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in Berry LLC’s historical balance sheet. The effects of the Plan and the application of fresh-start accounting are reflected in Berry Corp.’s consolidated financial statements as of the Effective Date and the related adjustments thereto are recorded in our consolidated statements of operations as reorganization items for the periods prior to the Effective Date. As a result, our consolidated financial statements subsequent to the Effective Date are not comparable to our financial statements prior to such date. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.
The summary unaudited pro forma financial information for the year ended December 31, 2017 is derived from the audited historical financial statements of Berry LLC and Berry Corp. included elsewhere in this prospectus. The summary unaudited pro forma financial information for the nine months ended September 30, 2018 is derived from the unaudited historical financial statements of Berry Corp. included elsewhere in this prospectus.
The summary unaudited pro forma financial information for the year ended December 31, 2017 has been prepared to give pro forma effect to (i) the Plan and related transactions and fresh-start accounting, (ii) our sale of an approximately 78% non-operated working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle on July 30, 2017 (the “Hugoton Disposition”), (iii) the 2026 Notes issuance and (iv) the Series A Preferred Stock Conversion and the IPO as if each had been completed as of January 1, 2017. The summary unaudited pro forma financial information does not give effect to the acquisition we made of the remaining approximately 84% non-operated working interest to consolidate with our existing 16% operated working interest in a South Belridge Hill property, located in Kern County, California, in the San Joaquin basin (the “Hill Acquisition”) because such transaction is not deemed significant under Rule 3-05 of the SEC’s Regulation S-X, so it is not required to be presented.
The summary unaudited pro forma financial information for the nine months ended September 30, 2018 has been prepared to give pro forma effect to (i) the 2026 Notes issuance and (ii) the Series A Preferred Stock Conversion and the IPO as if each had been completed as of January 1, 2017.
The summary unaudited pro forma financial information has been provided for informational and illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Plan, the Hugoton Disposition, the 2026 Notes issuance, the Series A Preferred Stock Conversion or the IPO had been put into effect on the dates indicated, nor are such financial statements necessarily indicative of the financial position or results of operations in future periods.
You should read the following summary information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the

14




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)
 
Nine Months Ended September 30, 2018
 
Ten Months Ended December 31, 2017
 
Seven Months Ended September 30, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
 
(unaudited)
 
(audited)
 
(unaudited)
 
 
(audited)
 
($ in thousands)
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and NGL sales
$
410,013

 
$
357,928

 
$
237,324

 
 
$
74,120

 
$
392,345

Electricity sales
25,691

 
21,972

 
15,517

 
 
3,655

 
23,204

Gains (losses) on oil derivatives
(131,781
)
 
(66,900
)
 
5,642

 
 
12,886

 
(15,781
)
Marketing revenues
1,788

 
2,694

 
1,901

 
 
633

 
3,653

Other revenues
500

 
3,975

 
3,902

 
 
1,424

 
7,570

Lease operating expenses
137,468

 
149,599

 
105,014

 
 
28,238

 
185,056

Electricity generation expenses
13,855

 
14,894

 
10,193

 
 
3,197

 
17,133

Transportation expenses
7,640

 
19,238

 
18,645

 
 
6,194

 
41,619

Marketing expenses
1,424

 
2,320

 
1,674

 
 
653

 
3,100

General and administrative expenses(1)
37,896

 
56,009

 
43,529

 
 
7,964

 
79,236

Depreciation, depletion and amortization
62,017

 
68,478

 
48,393

 
 
28,149

 
178,223

Impairment of long-lived assets

 

 

 
 

 
1,030,588

Taxes, other than income taxes
25,288

 
34,211

 
25,112

 
 
5,212

 
25,113

(Gains) losses on natural gas derivatives
(1,879
)
 

 

 
 

 

(Gains) losses on sale of assets and other, net
522

 
(22,930
)
 
(20,687
)
 
 
(183
)
 
(109
)
Interest expense
26,828

 
18,454

 
12,482

 
 
8,245

 
61,268

Other (income) expense, net
(135
)
 
(4,071
)
 
(4,071
)
 
 
63

 
182

Reorganization items, net (income) expense
(23,192
)
 
1,732

 
1,001

 
 
507,720

 
72,662

Income tax (benefit) expense
3,145

 
2,803

 
9,189

 
 
230

 
116

Net income (loss)
15,334

 
(21,068
)
 
13,812

 
 
(502,964
)
 
(1,283,196
)
Conversion and Dividends on Series A Preferred Stock
(97,942
)
 
(18,248
)
 
(12,681
)
 
 
n/a

 
n/a

Net income (loss) available to common stockholders
(82,608
)
 
(39,316
)
 
1,131

 
 
n/a

 
n/a

Net income (loss) per share of common stock
 
 
 
 
 
 
 
 
 
 
Basic
$
(1.59
)
 
$
(0.98
)
 
$
0.03

 
 
n/a

 
n/a

Diluted
$
(1.59
)
 
$
(0.98
)
 
$
0.03

 
 
n/a

 
n/a

Weighted average common stock outstanding
 
 
 
 
 
 
 
 
 
 
Basic
51,900

 
40,000

 
40,000

 
 
n/a

 
n/a

Diluted(2)
51,900

 
40,000

 
40,602

 
 
n/a

 
n/a

Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in)
 
 
 
 
 
 
 
 
 
 
Operating activities
$
7,334

 
$
107,399

 
$
70,505

 
 
$
22,431

 
$
13,197

Capital expenditures
(85,752
)
 
(65,479
)
 
(49,942
)
 
 
(3,158
)
 
(34,796
)
Acquisitions, sales of properties and other investing activities
3,377

 
(15,046
)
 
(24,621
)
 
 
25

 
194

Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
 
Total assets
$
1,539,607

 
$
1,546,402

 
$
1,579,389

 
 
$
1,561,038

 
$
2,652,050

Current portion of long-term debt

 

 

 
 

 
891,259

Long-term debt, net
391,512

 
379,000

 
379,000

 
 
400,000

 

Series A Preferred Stock

 
335,000

 
335,000

 
 
335,000

 

Stockholders’ and/or member’s equity
889,110

 
859,310

 
893,241

 
 
878,527

 
502,963

Other Financial Data:
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA(3)
$
176,256

 
$
149,613

 
$
96,773

 
 
$
28,845

 
$
89,646

Adjusted General and Administrative Expenses(4)
29,133

 
23,865

 
15,206

 
 
7,964

 
79,236


15




__________
(1)
Includes non-recurring restructuring and other costs and non-cash stock compensation expense, in aggregate, of $8.8 million for the nine months ended September 30, 2018, $32.1 million for the ten months ended December 31, 2017 and $28.3 million for the seven months ended September 30, 2017.
(2)
The Series A Preferred Stock was not a participating security; therefore, we calculated diluted earnings per share using the “if-converted” method, under which the preferred dividends are added back to the numerator and the Series A Preferred Stock is assumed to be converted at the beginning of the period. No incremental shares of Series A Preferred Stock were included in the diluted earnings per share calculation for the nine months ended September 30, 2018 and the ten months ended December 2017, as their effect was antidilutive under the “if-converted” method. In July 2018, all outstanding shares of our Series A Preferred Stock were converted to common shares in connection with the IPO. Please see “—Recent Developments—Initial Public Offering and Series A Preferred Stock Conversion.”
(3)
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.”
(4)
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
 
Nine Months Ended September 30, 2018
 
Year Ended
December 31, 2017
 
($ in thousands)
Statements of Operations Data:
 
 
 
Oil, natural gas and NGL sales
$
410,013

 
$
394,206

Gain (losses) on oil derivatives
(131,781
)
 
(54,014
)
Lease operating expenses
137,468

 
171,708

Transportation expenses
7,640

 
15,425

General and administrative expenses(1)
37,896

 
62,681

Depreciation, depletion and amortization
62,017

 
75,837

Taxes, other than income taxes
25,288

 
34,555

Interest expense
(26,828
)
 
(31,110
)
Reorganization items, net (income) expense
23,192

 
(1,732
)
Income tax (benefit) expense
3,124

 
1,800

Net income (loss)
15,233

 
(42,441
)
__________
(1)
Includes non-recurring restructuring and other costs and non-cash stock compensation expense of $8.8 million for the nine months ended September 30, 2018 and $32.1 million for the year ended December 31, 2017.

Non-GAAP Financial Measures
Adjusted EBITDA, Levered Free Cash Flow and Adjusted Net Income (Loss)
Adjusted EBITDA and Adjusted Net Income (Loss) are not measures of net income (loss) and Levered Free Cash Flow is not a measure of cash flow, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
Adjusted Net Income (Loss) excludes the impact of unusual, out-of-period and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items and the income tax expense or benefit of these adjustments using our effective tax rate.
We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, amortization and accretion; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including

16




restructuring costs and reorganization items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.
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. Levered Free Cash Flow is used by management as a primary metric to plan capital allocation for maintenance and internal growth opportunities, as well as hedging needs. It also serves as a measure for assessing our financial performance and our ability to generate excess cash from operations to service debt and pay dividends.
While Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow were computed in accordance with GAAP. These measures are 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, Adjusted Net Income (Loss) and Levered Free Cash Flow may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
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.

17




The following tables present reconciliations of the non-GAAP financial measures Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow to the GAAP financial measures of net income (loss) and net cash provided or used by operating activities, as applicable, for each of the periods indicated.
 
Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
Three Months Ended
September 30, 2018
 
Three Months Ended
June 30,
2018
 
Three Months Ended
September 30, 2017
 
Nine Months Ended
September 30, 2018
 
Ten Months Ended
December 31, 2017
 
Seven Months Ended
September 30, 2017
 
 
Two Months Ended
February 28, 2017
 
Year Ended
December 31, 2016
 
($ in thousands)
Adjusted EBITDA reconciliation to net income (loss):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
36,985

 
$
(28,061
)
 
$
(9,684
)
 
$
15,334

 
$
(21,068
)
 
$
13,812

 
 
$
(502,964
)
 
$
(1,283,196
)
Add (Subtract):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation, depletion, amortization and accretion
21,729

 
21,859

 
20,822

 
62,017

 
68,478

 
48,392

 
 
28,149

 
178,223

Interest expense
9,877

 
9,155

 
5,882

 
26,828

 
18,454

 
12,482

 
 
8,245

 
61,268

Income tax (benefit) expense
7,683

 
(5,476
)
 
(6,246
)
 
3,145

 
2,803

 
9,190

 
 
230

 
116

Derivative (gain) loss
17,115

 
78,143

 
42,443

 
129,902

 
66,900

 
(5,642
)
 
 
(12,886
)
 
20,386

Net cash received (paid) for scheduled derivative settlements
(1,052
)
 
(28,261
)
 
4,045

 
(47,161
)
 
3,068

 
9,902

 
 
534

 
9,708

(Gain) loss on sale of assets and other
400

 
123

 
(20,692
)
 
522

 
(22,930
)
 
(20,687
)
 
 
(183
)
 
(109
)
Impairments

 

 

 

 

 

 
 

 
1,030,588

Stock compensation expense
1,182

 
1,278

 
902

 
3,502

 
1,851

 
902

 
 

 

Non-recurring restructuring and other costs
1,598

 
1,714

 
2,979

 
5,359

 
30,325

 
27,421

 
 

 

Reorganization items, net
(13,781
)
 
(456
)
 
408

 
(23,192
)
 
1,732

 
1,001

 
 
507,720

 
72,662

Adjusted EBITDA(1)
$
81,736

 
$
50,018

 
$
40,859

 
$
176,256

 
$
149,613

 
$
96,773

 
 
$
28,845

 
$
89,646

__________
(1)
Adjusted EBITDA includes cash paid for scheduled derivative settlements of $1 million for the three months ended September 30, 2018, $28 million for the three months ended June 30, 2018, and $47 million for the nine months ended September 30, 2018; and includes cash received for scheduled derivative settlements of $4 million for the three months ended September 30, 2017, $3 million for the ten months ended December 31, 2017, $10 million for the seven months ended September 30, 2017, $1 million for the two months ended February 28, 2017, and $10 million for the year ended December 31, 2016.

18




 
Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
Three Months Ended
September 30, 2018
 
Three Months Ended
June 30,
2018
 
Three Months Ended
September 30, 2017
 
Nine Months Ended
September 30, 2018
 
Ten Months Ended
December 31, 2017
 
Seven Months Ended
September 30, 2017
 
 
Two Months Ended
February 28, 2017
 
Year Ended
December 31, 2016
 
($ in thousands)
Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided (used) by operating activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
56,880

 
$
(77,394
)
 
$
25,568

 
$
7,334

 
$
107,399

 
$
70,505

 
 
$
22,431

 
$
13,197

Add (Subtract):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash interest payments
15,902

 
644

 
4,726

 
19,199

 
14,276

 
9,987

 
 
8,057

 
57,759

Cash income tax payments

 

 
826

 

 
1,994

 
1,994

 
 

 
347

Cash reorganization item (receipts) payments
(345
)
 
1,047

 
417

 
1,007

 
1,732

 
(375
)
 
 
11,838

 
19,116

Non-recurring restructuring and other costs
1,598

 
1,714

 
2,979

 
5,359

 
30,325

 
27,421

 
 

 

Derivative early termination payment

 
126,949

 

 
126,949

 

 

 
 

 

Other changes in operating assets and liabilities
7,701

 
(2,942
)
 
6,343

 
16,408

 
(6,113
)
 
(12,759
)
 
 
(13,323
)
 
(876
)
Other, net

 

 

 

 

 

 
 
(158
)
 
103

Adjusted EBITDA
81,736

 
50,018

 
40,859

 
176,256

 
149,613

 
96,773

 
 
28,845

 
89,646

Subtract:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital expenditures - accrual basis
(40,243
)
 
(38,531
)
 
(16,902
)
 
(94,505
)
 
(65,479
)
 
(50,953
)
 
 
(5,406
)
 
(34,796
)
Interest expense
(9,877
)
 
(9,155
)
 
(5,882
)
 
(26,828
)
 
(18,454
)
 
(12,482
)
 
 
(8,245
)
 
(61,268
)
Cash dividends declared
(7,431
)
 
(5,651
)
 

 
(18,732
)
 
(18,248
)
 

 
 

 

Levered Free Cash Flow(1)
$
24,185

 
$
(3,319
)
 
$
18,075

 
$
36,191

 
$
47,432

 
$
33,338

 
 
$
15,194

 
$
(6,418
)
__________
(1)
Levered Free Cash Flow includes cash paid for scheduled derivative settlements of $1 million for the three months ended September 30, 2018, $28 million for the three months ended June 30, 2018, and $47 million for the nine months ended September 30, 2018; and includes cash received for scheduled derivative settlements of $4 million for the three months ended September 30, 2017, $3 million for the ten months ended December 31, 2017, $10 million for the seven months ended September 30, 2017, $1 million for the two months ended February 28, 2017, and $10 million for the year ended December 31, 2016.

19




The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss) to the GAAP financial measure of Net income (loss).
 
Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
Three Months Ended
September 30, 2018
 
Three Months Ended
June 30, 2018
 
Three Months Ended
September 30, 2017
 
Nine Months Ended
September 30, 2018
 
Ten Months Ended
December 31, 2017
 
Seven Months Ended
September 30, 2017
 
 
Two Months Ended
February 28, 2017
 
Year Ended
December 31, 2016
 
($ in thousands)
Adjusted Net Income (Loss) reconciliation to Net income (loss)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
36,985

 
$
(28,061
)
 
$
(9,684
)
 
$
15,334

 
$
(21,068
)
 
$
13,812

 
 
$
(502,964
)
 
$
(1,283,196
)
Add (Subtract):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Gains) losses on oil and natural gas derivatives
17,115

 
78,143

 
42,443

 
129,902

 
66,900

 
(5,642
)
 
 
(12,886
)
 
20,386

Net cash received (paid) for scheduled derivative settlements
(1,052
)
 
(28,261
)
 
4,045

 
(47,161
)
 
3,068

 
9,902

 
 
534

 
9,708

(Gains) losses on sale of assets and other, net
400

 
123

 
(20,692
)
 
522

 
(22,930
)
 
(20,687
)
 
 
(183
)
 
(109
)
Impairments

 

 

 

 

 

 
 

 
1,030,588

Non-recurring restructuring and other costs
1,598

 
1,714

 
2,979

 
5,359

 
30,325

 
27,421

 
 

 

Reorganization items, net
(13,781
)
 
(456
)
 
408

 
(23,192
)
 
1,732

 
1,001

 
 
507,720

 
72,662

Total additions, net
4,280

 
51,263

 
29,183

 
65,430

 
79,095

 
11,995

 
 
495,185

 
1,133,235

Income tax benefit (expense) of adjustments at effective tax rate
(736
)
 
(8,371
)
 
(11,673
)
 
(11,137
)
 
(22,147
)
 
(4,798
)
 
 

 

Adjusted Net Income (Loss)
$
40,529

 
$
14,831

 
$
7,826

 
$
69,627

 
$
35,880

 
$
21,009

 
 
$
(7,779
)
 
$
(149,961
)
__________
(1)
For the ten months ended December 31, 2017, our effective tax rate was (15%) due to a net loss and valuation allowances. For purposes of this calculation, we used the statutory rate for this period, which was 28%.

The following table presents a reconciliation of the non-GAAP financial measure 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)
 
Three Months Ended
September 30, 2018
 
Three Months Ended
June 30,
2018
 
Three Months Ended
September 30, 2017
 
Nine Months Ended
September 30, 2018
 
Ten Months
Ended
December 31, 2017
 
Seven Months Ended
September 30, 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
$
13,429

 
$
12,482

 
$
11,729

 
$
37,896

 
$
56,009

 
$
43,529

 
 
$
7,964

 
$
79,236

Subtract:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-recurring restructuring and other costs
(1,598
)
 
(1,714
)
 
(2,979
)
 
(5,359
)
 
(30,325)

 
(27,421
)
 
 

 

Non-cash stock compensation expense
(1,125
)
 
(1,260
)
 
(902
)
 
(3,404
)
 
(1,819)

 
(902
)
 
 

 

Adjusted General and Administrative Expenses
$
10,706

 
$
9,508

 
$
7,848

 
$
29,133

 
$
23,865

 
$
15,206

 
 
$
7,964

 
$
79,236


20




Summary Reserves and Operating Data
The following tables present summary data with respect to our estimated proved oil, natural gas and NGL reserves and operating data as of the dates presented. In evaluating the material presented below, please see “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Our Reserves and Production Information” and our financial statements and notes thereto. Our historical results of operations are not necessarily indicative of results to be expected for any future period.
Reserves
The following table summarizes our estimated proved reserves and related PV-10 using SEC Pricing as of December 31, 2017 and Strip Pricing as of May 31, 2018. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton. The SEC Pricing reserve estimates were prepared in accordance with current SEC rules and regulations regarding oil, natural gas and NGL reserve reporting and Strip Pricing data was prepared using closing month futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX (HH) for natural gas on May 31, 2018. Reserves are stated net of applicable royalties.
 
SEC Pricing as of December 31, 2017(1)
 
Strip Pricing as of May 31, 2018(2)
 
San Joaquin and Ventura basins
 
Uinta basin
 
Piceance basin
 
East Texas basin(3)
 
Total
 
San Joaquin and Ventura basins
 
Uinta basin
 
Piceance basin
 
East Texas basin(3)
 
Total
Proved developed reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
61

 
7

 

 

 
68

 
63

 
7

 

 

 
70

Natural Gas (Bcf)

 
47

 
42

 
12

 
100

 

 
41

 
17

 
9

 
67

NGLs (MMBbl)

 
1

 

 

 
1

 

 
1

 

 

 
1

Total (MMBoe)(4)(5)
61

 
16

 
7

 
2

 
86

 
63

 
15

 
3

 
2

 
82

Proved undeveloped reserves(7):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
32

 

 

 

 
32

 
32

 

 

 

 
32

Natural Gas (Bcf)

 

 
137

 

 
137

 

 

 

 

 

NGLs (MMBbl)

 

 

 

 

 

 

 

 

 

Total (MMBoe)(5)
32

 

 
23

 

 
55

 
32

 

 

 

 
32

Total proved reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
93

 
7

 

 

 
101

 
95

 
7

 

 

 
102

Natural Gas (Bcf)

 
47

 
179

 
12

 
237

 

 
41

 
17

 
9

 
67

NGLs (MMBbl)

 
1

 

 

 
1

 

 
1

 

 

 
1

Total (MMBoe)(5)
93

 
16

 
30

 
2

 
141

 
95

 
15

 
3

 
2

 
115

PV-10 ($MM)(6)
998

 
84

 
24

 
7

 
1,114

 
1,762

 
91

 
4

 
5

 
1,862

__________
(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 (HH) for natural gas at December 31, 2017. The volume-weighted average prices over the lives of the properties were $48.20 per barrel of oil and condensate, $28.25 per barrel of NGL and $2.935 per thousand cubic feet of gas. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. 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 and directly affect our results.”
(2)
Our Strip Pricing reserves were prepared on the same basis as our SEC reserves and do not include changes to costs, other economic parameters, well performance or drilling activity subsequent to December 31, 2017, except for the use of pricing based on closing month futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX (HH) for natural gas on May 31, 2018 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance.

Our Strip Pricing oil, natural gas and NGL reserves were determined using index prices for natural gas and oil, respectively, as of May 31, 2018 without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our Strip Pricing reserves were $74.59 per Bbl for oil and NGLs for 2018, $72.98 for 2019, $69.15 for 2020 and $66.49 for 2021 thereafter, on the ICE (Brent), and $2.94 per MMBtu for natural gas for 2018, $2.75 for 2019, $2.68 for 2020 and $2.66 for 2021 thereafter, on the NYMEX (HH). The volume-weighted average prices over the lives of the properties were $61.67 per barrel of oil and condensate, $19.49 per barrel of NGL,

21




and $1.943 per thousand cubic feet of gas. We have taken into account pricing differentials reflective of the market environment and NGL pricing used in determining our Strip Pricing reserves was approximately ICE (Brent) for oil less $49.00.

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

The decrease in reserve volumes using Strip Pricing as opposed to SEC Pricing is primarily the result of lower realized gas prices in Colorado using Strip Pricing as of May 31, 2018.
(3)
On October 17, 2018, we signed an agreement to sell our non-core oil and gas properties and related assets located in the East Texas Basin. We anticipate closing this sale in the fourth quarter of 2018.
(4)
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.
(5)
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 (HH) 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.
(6)
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.
(7)
Using SEC Pricing as of December 31, 2017, there were approximately 23 MMBoe of PUDs associated with projects in the Piceance basin. Subsequent to year end, as a result of increasingly negative local gas pricing differentials, we revised our current development plan to exclude these Piceance locations.

PV-10
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. Calculation of PV-10 does not give effect to derivatives transactions. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows using SEC Pricing at December 31, 2017:
 
At December 31, 2017
 
($ in millions)
PV-10
$
1,114

Less: present value of future income taxes discounted at 10%
(137
)
Standardized measure of discounted future net cash flows
$
977

GAAP does not prescribe any corresponding measure for PV-10 of reserves as of an interim date or on any basis other than SEC prices. As a result, it is not practicable for us to reconcile PV-10 using Strip Pricing as of May 31, 2018 to GAAP standardized measure.
Production and Operating Data
The following table sets forth information regarding production, realized and benchmark prices, and production costs (i) on a historical basis for the year ended December 31, 2016, the two months ended February 28, 2017, the seven months ended September 30, 2017, the ten months ended December 31, 2017 and the nine months ended September 30, 2018 and (ii) on a pro forma basis for the year ended December 31, 2017.

22




The pro forma information has been prepared to give pro forma effect to (i) the Plan and related transactions and fresh-start accounting and (ii) the Hugoton Disposition, as if each had been completed as of January 1, 2017, respectively. The summary unaudited pro forma financial information does not give effect to the Hill Acquisition because such transaction is not deemed significant under Rule 3-05 of the SEC’s Regulation S-X, so it is not required to be presented herein. For more information, see “—Summary Historical and Pro Forma Financial Information.”
For additional information regarding pricing dynamics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Environment and Market Conditions.”
 
Pro Forma(4)
 
Berry Corp.(Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2017
 
Nine Months Ended September 30, 2018
 
Ten Months Ended December 31, 2017
 
Seven Months Ended September 30, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
Production Data(5):
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbl/d)
20.5

 
21.5

 
20.6

 
20.0

 
 
19.5

 
23.1

Natural gas (MMcf/d)
31.2

 
27.7

 
49.4

 
57.2

 
 
71.7

 
78.1

NGLs (MBbl/d)
0.6

 
0.6

 
2.0

 
2.6

 
 
5.2

 
3.6

Average daily combined production (MBoe/d)(1)
26.3

 
26.7

 
30.9

 
32.1

 
 
36.7

 
39.7

Oil (MBbl)
7,471

 
5,867

 
6,318

 
4,288

 
 
1,153

 
8,463

Natural gas (MMcf)
11,382

 
7,555

 
15,119

 
12,241

 
 
4,232

 
28,577

NGLs (MBbl)
216

 
157

 
605

 
552

 
 
304

 
1,307

Total combined production (MBoe)(1)
9,584

 
7,284

 
9,443

 
6,880

 
 
2,162

 
14,533

Weighted average realized prices:
 
 
 
 
 
 
 
 
 
 
 
 
Oil with hedges (per Bbl)
$
48.37

 
$
57.96

 
$
48.53

 
$
47.17

 
 
$
47.40

 
$
36.88

Oil without hedges (per Bbl)
$
47.89

 
$
65.97

 
$
48.05

 
$
44.87

 
 
$
46.94

 
$
35.83

Natural gas (per Mcf)
$
2.82

 
$
2.44

 
$
2.70

 
$