UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended JuneSeptember 30, 20182020
OR
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from_______________ to _______________
Commission file number 001-38606



BERRY PETROLEUM CORPORATION

Berry Corporation (bry)
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation or organization)
81-5410470
(I.R.S. Employer Identification Number)
5201 Truxtun Avenue16000 Dallas Parkway, Suite 500
Bakersfield, California 93309Dallas, Texas 75248
(661) 616-3900
(Address of principal executive offices, including zip code
Registrant’s telephone number, including area code):


Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $0.001 per share
Trading Symbol
BRY
Name of each exchange on which registered
Nasdaq Global Select Market

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


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý☒    No ¨☐


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or emerging growth company. See definitions of “large accelerated filer,” “accelerated filer”,“smallerfiler,” “smaller reporting company” and "emerging“emerging growth company"company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
☐
Accelerated filer ¨
☐
Non-accelerated filer x
☒
Smaller reporting company ¨
☐
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 13(a) of the Exchange Act ¨Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨☐    No ý☒



Shares of common stock outstanding as of JulyOctober 31, 2018                        81,336,762

TABLE OF CONTENTS

2020          79,929,335


Table of Contents
Page
Item 1.Page
Part I- Financial Information
Item 1.
Financial Statements (unaudited)
Condensed Consolidated Balance Sheets
31
Condensed Consolidated Statements of Operations
42
Condensed Consolidated StatementStatements of Equity
53
Condensed Consolidated Statements of Cash Flows
65
Notes to Condensed Consolidated Financial Statements
76
Item 2.
2618
Item 3.
5857
Item 4.
59
Item 1.
5960
Item 1A.
5960
Item 5.2.
6064
Item 6.
6165
6366
6874



The financial information and certain other information presented in this report 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 report. In addition, certain percentages presented in this report 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.






Table of Contents
PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)


BERRY PETROLEUM CORPORATION (bry)
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share amounts)
(Unaudited)
 Berry Corp. (Successor)
 June 30, 2018December 31, 2017
ASSETS

Current assets:

Cash and cash equivalents$3,600
$33,905
Accounts receivable, net of allowance for doubtful accounts of $950 at June 30, 2018 and $970 at December 31, 201756,860
54,720
Restricted cash19,710
34,833
Other current assets14,981
14,066
Total current assets95,151
137,524
Noncurrent assets:

Oil and natural gas properties1,382,777
1,342,453
Accumulated depletion and amortization(88,548)(54,785)
 1,294,229
1,287,668
Other property and equipment112,618
104,879
Accumulated depreciation(8,928)(5,356)
 103,690
99,523
Other noncurrent assets22,086
21,687
Total assets$1,515,156
$1,546,402
LIABILITIES AND EQUITY

Current liabilities:

Accounts payable and accrued expenses$113,170
$97,877
Derivative instruments11,447
49,949
Liabilities subject to compromise19,710
34,833
Total current liabilities144,327
182,659
Noncurrent liabilities:

Long-term debt457,333
379,000
Derivative instruments3,563
25,332
Deferred income taxes—
1,888
Asset retirement obligation88,575
94,509
Other noncurrent liabilities12,862
3,704
Commitments and Contingencies-Note 5


Equity:

Series A Preferred Stock ($.001 par value, 250,000,000 shares authorized and 37,669,805 shares issued at June 30, 2018 and 35,845,001 shares issued at December 31, 2017)335,000
335,000
Common stock ($.001 par value, 750,000,000 shares authorized and 33,087,889 shares issued at June 30, 2018 and 32,920,000 issued at December 31, 201733
33
Additional paid-in-capital536,188
545,345
Treasury stock, at cost(20,006)—
Accumulated deficit(42,719)(21,068)
Total equity808,496
859,310
Total liabilities and equity$1,515,156
$1,546,402
The accompanying notes are an integral part of these condensed consolidated financial statements

BERRY PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
(unaudited)
 Berry Corp.
(Successor)		Berry LLC
(Predecessor)
 Three Months EndedThree Months Ended Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017 June 30, 2018June 30, 2017February 28, 2017
Revenues and other:



 





Oil, natural gas and natural gas liquids sales$137,385
$101,884
 $263,010
$135,562
$74,120
Electricity sales5,971
5,712
 11,423
6,603
3,655
(Losses) gains on oil and natural gas derivatives(78,143)23,962
 (112,787)48,085
12,886
Marketing revenues518
809
 1,302
1,090
633
Other revenues251
2,355
 317
3,037
1,424

65,982
134,722
 163,265
194,377
92,718
Expenses and other:      
Lease operating expenses41,517
45,726
 85,819
58,790
28,238
Electricity generation expenses3,135
4,465
 7,725
5,613
3,197
Transportation expenses2,343
9,404
 5,321
13,059
6,194
Marketing expenses407
730
 987
1,000
653
General and administrative expenses12,482
22,257
 24,466
31,800
7,964
Depreciation, depletion, amortization and accretion21,859
20,549
 40,288
27,571
28,149
Taxes, other than income taxes8,715
10,249
 16,972
13,330
5,212
(Gains) losses on sale of assets and other, net123
5
 123
5
(183)

90,581
113,385
 181,701
151,168
79,424
Other income and (expenses):      
Interest expense(9,155)(4,885) (16,951)(6,600)(8,245)
Other, net(239)2,916
 (212)2,916
(63)

(9,394)(1,969) (17,163)(3,684)(8,308)
Reorganization items, net456
713
 9,411
(593)(507,720)
Income (loss) before income taxes(33,537)20,081
 (26,188)38,932
(502,734)
Income tax expense (benefit)(5,476)7,961
 (4,537)15,435
230
Net income (loss)(28,061)12,120
 (21,651)23,497
$(502,964)
Dividends on Series A Preferred Stock(5,650)(5,404) (11,301)(7,196)n/a
Net income (loss) attributable to common stockholders$(33,711)$6,716
 $(32,952)$16,301
n/a
Net income (loss) per share attributable to common stockholders:      
Basic$(0.84)$0.17
 $(0.82)$0.41
n/a
Diluted$(0.84)$0.16
 $(0.82)$0.31
n/a
September 30, 2020December 31, 2019
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents$47,620 $0 
Accounts receivable, net of allowance for doubtful accounts of $2,215 at September 30, 2020 and $1,103 at December 31, 201948,798 71,867 
Derivative instruments57,658 9,166 
Other current assets20,318 19,399 
Total current assets174,394 100,432 
Noncurrent assets:
Oil and natural gas properties1,388,544 1,675,717 
Accumulated depletion and amortization(209,956)(209,105)
Total oil and natural gas properties, net1,178,588 1,466,612 
Other property and equipment111,146 135,117 
Accumulated depreciation(28,979)(25,462)
Total other property and equipment, net82,167 109,655 
Derivative instruments2,011 525 
Other noncurrent assets9,297 12,974 
Total assets$1,446,457 $1,690,198 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses$95,237 $151,811 
Derivative instruments337 4,817 
Total current liabilities95,574 156,628 
Noncurrent liabilities:
Long-term debt393,219 394,319 
Derivative instruments1,179 141 
Deferred income taxes9,318 9,057 
Asset retirement obligation136,392 124,019 
Other noncurrent liabilities36,150 33,586 
Commitments and Contingencies - Note 4
Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 85,004,619 and 84,655,222 shares issued; and 79,892,373 and 79,542,976 shares outstanding, at September 30, 2020 and December 31, 2019, respectively)85 85 
Additional paid-in-capital912,637 901,830 
Treasury stock, at cost, (5,112,246 shares at September 30, 2020 and at December 31, 2019)(49,995)(49,995)
Retained earnings (deficit)(88,102)120,528 
Total equity774,625 972,448 
Total liabilities and equity$1,446,457 $1,690,198 
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
Table of Contents

BERRY PETROLEUM CORPORATION (Successor)(bry)
CONDENSED CONSOLIDATED STATEMENTSTATEMENTS OF EQUITY
(in thousands)OPERATIONS
(Unaudited)

Three Months Ended
September 30,		Nine Months Ended
September 30,
2020201920202019
(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales$92,239 $141,250 $284,852 $409,259 
Electricity sales8,744 7,460 19,089 22,553 
(Losses) gains on oil derivatives(11,564)45,509 157,398 7,546 
Marketing revenues330 413 1,075 1,657 
Other revenues0 40 53 261 
Total revenues and other89,749 194,672 462,467 441,276 
Expenses and other:
Lease operating expenses45,243 50,957 136,727 156,765 
Electricity generation expenses4,217 3,781 11,186 14,705 
Transportation expenses1,768 2,067 5,379 5,935 
Marketing expenses326 398 1,036 1,670 
General and administrative expenses19,173 16,434 57,287 46,932 
Depreciation, depletion, and amortization35,905 27,664 108,746 75,904 
Impairment of oil and gas properties0 0 289,085 0 
Taxes, other than income taxes9,913 9,249 24,714 28,683 
(Gain) losses on natural gas derivatives(15,784)3,008 (2,824)10,342 
Other operating expenses (income)1,648 (550)2,658 3,814 
Total expenses and other102,409 113,008 633,994 344,750 
Other (expenses) income:
Interest expense(8,391)(8,597)(25,987)(26,362)
Other, net(3)(77)(15)79 
Total other (expenses) income(8,394)(8,674)(26,002)(26,283)
Reorganization items, net0 (170)0 (426)
(Loss) income before income taxes(21,054)72,820 (197,529)69,817 
Income tax (benefit) expense(2,190)20,171 1,536 19,294 
Net (loss) income$(18,864)$52,649 $(199,065)$50,523 
Net (loss) income per share:
Basic$(0.24)$0.65 $(2.50)$0.62 
Diluted$(0.24)$0.65 $(2.50)$0.62 



Series A Preferred StockCommon stockAdditional Paid-in CapitalAccumulated DeficitTreasury StockTotal equity
Balance, December 31, 2017$335,000
$33
$545,345
$(21,068)$—
$859,310
Stock-based compensation—
—
2,320
—
—
2,320
Share repurchase for payment of taxes on equity awards—
—
(176)—
—
(176)
Cash dividends declared on Series A Preferred Stock—
—
(11,301)—
—
(11,301)
Purchase of rights to common stock—
—
—
—
(20,006)(20,006)
Net (loss) income—
—
—
(21,651)—
(21,651)
Balance, June 30, 2018$335,000
$33
$536,188
$(42,719)$(20,006)$808,496




The accompanying notes are an integral part of these condensed consolidated financial statements.
2
Table of Contents

BERRY PETROLEUM CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWSEQUITY
((Unaudited)


Nine-Month Period Ended September 30, 2019
Common StockAdditional Paid-in CapitalTreasury StockRetained EarningsTotal Equity
(in thousands)
December 31, 2018$82 $914,540 $(24,218)$116,042 $1,006,446 
Shares withheld for payment of taxes on equity awards and other— (270)— — (270)
Stock based compensation— 1,498 — — 1,498 
Purchases of treasury stock— — (24,375)— (24,375)
Purchase of rights to common stock(1)
— (20,265)20,265 — 0 
Common stock issued to settle unsecured claims3 (3)— — 0 
Dividends declared on common stock, $0.12/share— — — (10,072)(10,072)
Net loss— — — (34,098)(34,098)
March 31, 201985 895,500 (28,328)71,872 939,129 
Shares withheld for payment of taxes on equity awards and other— (675)— — (675)
Stock based compensation— 2,497 — — 2,497 
Purchases of treasury stock— — (10,897)— (10,897)
Dividends declared on common stock, $0.12/share— — — (9,710)(9,710)
Net income— — — 31,972 31,972 
June 30, 201985 897,322 (39,225)94,134 952,316 
Shares withheld for payment of taxes on equity awards and other— (294)— — (294)
Stock based compensation— 2,393 — — 2,393 
Dividends declared on common stock, $0.12/share— — — (9,720)(9,720)
Net income— — — 52,649 52,649 
September 30, 2019$85 $899,421 $(39,225)$137,063 $997,344 
__________
(1) In 2018, we entered into several settlement agreements with general unsecured creditors from our bankruptcy process. We paid approximately $20 million to purchase their claims to our common stock. These claims were settled in thousands)February 2019 with 0 shares issued.
(Unaudited)
 Berry Corp.Berry LLC
 (Successor)(Predecessor)
 Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017February 28, 2017
Cash flow from operating activities:   
Net income (loss)$(21,651)$23,497
$(502,964)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:   
Depreciation, depletion, amortization and accretion40,288
27,571
28,149
Amortization of debt issuance costs2,651
7
416
Stock-based compensation expense2,320
—
—
Deferred income taxes(4,537)14,268
9
(Decrease) increase in allowance for doubtful accounts(20)—
—
Derivative activities:   
  Total (gains) losses112,787
(48,085)(12,886)
     Cash settlements(46,110)5,856
534
  Cash settlements on early-terminated derivatives(126,949)—
—
(Gains) losses on sale of assets and other, net123
(25)(25)
Reorganization items, net(10,763)(1,385)501,872
Changes in assets and liabilities:   
  (Increase) decrease in accounts receivable(2,120)16,543
(9,152)
  (Increase) decrease in other assets(1,859)(5,657)(2,842)
  Increase (decrease) in accounts payable and accrued expenses8,421
2,461
18,330
  Increase (decrease) in other liabilities(2,129)9,886
990
Net cash (used in) provided by operating activities(49,548)44,937
22,431
    
Cash flows from investing activities:   
Capital expenditures:   
  Development of oil and natural gas properties(37,609)(23,258)(859)
  Purchases of other property and equipment(7,760)(9,620)(2,299)
  Proceeds from sale of property, plant, equipment and other3,022
—
25
     Deposit on acquisition of properties—
(39,450)—
Net cash used in investing activities(42,347)(72,328)(3,133)
    
Cash flows from financing activities:   
Proceeds from sale of Series A Preferred Stock—
—
335,000
Repayments on pre-emergence credit facility—
—
(497,668)
Borrowings on emergence credit facility—
36,000
—
Repayments on emergence credit facility—
(51,000)—
Proceeds from issuance of senior unsecured notes400,000
—
—
Repayments on new credit facility(409,800)—
—
Borrowings on new credit facility96,800
—
—
Dividends paid on Series A Preferred Stock(11,301)—
—
Purchase of treasury stock(20,006)—
—
Share repurchase for payment of taxes on equity awards(176)—
—
Debt issuance costs(9,050)—
—
Net cash provided by (used in) financing activities46,467
(15,000)(162,668)
Net decrease in cash, cash equivalents and restricted cash(45,428)(42,391)(143,370)
Cash, cash equivalents and restricted cash:   
Beginning68,738
85,034
228,404
Ending$23,310
$42,643
$85,034

The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Table of Contents

BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)


Nine-Month Period Ended September 30, 2020
Common StockAdditional Paid-in CapitalTreasury Stock Retained Earnings (Deficit)Total Equity
(in thousands)
December 31, 2019$85 $901,830 $(49,995)$120,528 $972,448 
Shares withheld for payment of taxes on equity awards and other— (794)— — (794)
Stock based compensation— 3,036 — — 3,036 
Dividends declared on common stock, $0.12/share— — — (9,564)(9,564)
Net loss— — — (115,300)(115,300)
March 31, 202085 904,072 (49,995)(4,336)849,826 
Shares withheld for payment of taxes on equity awards and other— (140)— — (140)
Stock based compensation— 4,730 — — 4,730 
Net loss— — — (64,901)(64,901)
June 30, 202085 908,662 (49,995)(69,237)789,515 
Shares withheld for payment of taxes on equity awards and other— (46)— — (46)
Stock based compensation— 4,021 — — 4,021 
Net loss— — — (18,864)(18,864)
September 30, 2020$85 $912,637 $(49,995)$(88,102)$774,625 

The accompanying notes are an integral part of these condensed consolidated financial statements.
4
Table of Contents
BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
20202019
(in thousands)
Cash flows from operating activities:
Net (loss) income$(199,065)$50,523 
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization108,746 75,904 
Amortization of debt issuance costs3,990 3,786 
Impairment of oil and gas properties289,085 0 
Stock-based compensation expense11,397 6,277 
Deferred income taxes(702)19,294 
Increase in allowance for doubtful accounts1,112 427 
Other operating expenses2,145 4,744 
Derivative activities:
Total (gains) losses(160,222)2,796 
Cash settlements on derivatives106,975 26,731 
Changes in assets and liabilities:
Decrease (increase) in accounts receivable21,985 (6,690)
Increase in other assets(919)(2,073)
Decrease in accounts payable and accrued expenses(29,882)(12,344)
Decrease in other liabilities(10,226)(5,108)
Net cash provided by operating activities144,419 164,267 
Cash flows from investing activities:
Capital expenditures:
Development of oil and natural gas properties(58,370)(157,281)
Purchases of other property and equipment(3,951)(12,394)
Changes in capital investment accruals(10,347)(4,613)
Acquisition of properties and equipment and other(2,104)(2,819)
Proceeds from sale of property and equipment and other250 969 
Net cash used in investing activities(74,522)(176,138)
Cash flows from financing activities:
Borrowings under RBL credit facility228,900 252,182 
Repayments on RBL credit facility(230,750)(242,182)
Dividends paid on common stock(19,447)(29,431)
Purchase of treasury stock0 (36,139)
Shares withheld for payment of taxes on equity awards and other(980)(1,239)
Net cash used in financing activities(22,277)(56,809)
Net increase (decrease) in cash and cash equivalents47,620 (68,680)
Cash and cash equivalents:
Beginning0 68,680 
Ending$47,620 $0 


The accompanying notes are an integral part of these condensed consolidated financial statements.
5
Table of Contents
BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)






Note 1 - 1—Basis of Presentation
“Berry Corp.” refers to Berry Petroleum Corporation (bry), a Delaware corporation, which on and after February 28, 2017 is the sole member of Berry Petroleum Company, LLC.
“LLC ("Berry LLC” refers to Berry Petroleum Company, LLC, a Delaware limited liability company.LLC").
As the context may require, the “Company”, “we”, “our” or similar words refer to (i) Berry Corp. (the "Successor”) and Berry LLC, its consolidated subsidiary, as of and after February 28, 2017, as a whole or (ii) either Berry Corp. or Berry LLC on an individual basis as of and after February 28, 2017. References to historical activities of the “Company” prior to February 28, 2017, refer to activities of Berry LLC (the "Predecessor”).LLC.
“LINN Energy” refers to Linn Energy, LLC, a Delaware limited liability company of which Berry LLC was formerly a wholly-owned, indirect subsidiary.
Nature of Business
Berry Corp. is an independent oil and natural gas company that was incorporated under Delaware law in February 2017 and its common stock began trading on February 13, 2017.NASDAQ under the symbol "bry" in July 2018. Berry Corp. operates through its wholly-owned subsidiary, Berry LLC. Our properties are located onshore in the United States (“U.S.(the “U.S.”), in California (in the San Joaquin and Ventura Basins)basins), Utah (in the Uinta Basin)basin), and Colorado (in the Piceance Basin) and east Texas.
In July, we completed the initial public offering ("IPO") of our common stock and as a result, on July 26, 2018, our common stock began trading on the NASDAQ Global Select Market under the ticker symbol BRY.basin).
Principles of Consolidation and Reporting
The information reported herein reflects all adjustments (consisting of normal recurring adjustments) that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annualcondensed consolidated financial statements were prepared in accordanceconformity with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities, which requires management to make estimates and Exchange Commission (“SEC”) rules and regulations. The resultsassumptions that affect the amounts reported in thesethe financial statements and accompanying notes. In management’s opinion, the accompanying financial statements contain all normal, recurring adjustments that are necessary to fairly present our interim unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year. This report should be read in conjunction with the financial statements and notes in the Company's audited financial statements for the year ended December 31, 2017 presented in our final prospectus dated July 25, 2018 as filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on July 27, 2018 (the "prospectus").
The condensed consolidated financial statements have been prepared in conformity with GAAP and include the accounts of the Successor and its wholly owned subsidiary after February 28, 2017 and the accounts of the Predecessor prior to February 28, 2017. Allstatements. We eliminated all significant intercompany transactions and balances have been eliminated upon consolidation. For oil and gas exploration and production joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements.
Bankruptcy Accounting
Upon emergence from bankruptcy on February 28, 2017, we adopted fresh start accounting which resulted in Berry Corp. becomingWe prepared this report pursuant to the financial reporting entity. As a resultrules and regulations of the applicationU.S. Security and Exchange Commission (“SEC”) applicable to interim financial information, which permit the omission of fresh start accounting andcertain disclosures to the effects ofextent they have not changed materially since the implementation oflatest annual financial statements. We believe our disclosures are adequate to make the Plan, thedisclosed information not misleading. The results reported in these unaudited condensed consolidated financial statements may not accurately forecast results for future periods. This Quarterly Report on or after February 28, 2017 are not comparable toForm 10-Q should be read in conjunction with the condensed consolidated financial statements prior to that date.
Use of Estimates
The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP required management of the Company to make informed estimates and assumptions about future events. These estimates and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2019.

Reclassification
BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




underlying assumptions affectWe reclassified certain prior year amounts in the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.
As fair value is a market-based measurement, it was determined basedcash flow statements to conform to the current year presentation. These reclassifications had no material impact on the assumptions that we believe market participants would use. We based these assumptions on management's best estimates and judgment. Management evaluates its assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, that management believes to be reasonable under the circumstances. Such assumptions are adjusted when management determines that facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in these assumptions resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
The estimates that are particularly significant to our financial statements include estimates of our reserves of oil and gas, future cash flows from oil and gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. In addition, as part of fresh-start accounting, we made estimates and assumptions related to our reorganization value, liabilities subject to compromise and the fair value of assets and liabilities recorded.
Accounting and Disclosure Changes
Recently Adopted Accounting Standards
In March 2016, the Financial Accounting Standards Board (“FASB”) issued rules to improve the accounting for share-based payment transactions. We early-adopted these rules retrospectively on April 1, 2018 and as a result are reporting cash paid to tax authorities when we withhold shares from an employee's award as a cash outflow for financing activities on the statement of cash flows. There was no change to the other financial statements as a result of adopting these rules.

In November 2016, the FASB issued rules intended to address the diversity in practice in classification and presentation of changes in restricted cash on the statement of cash flows. We adopted these rules retrospectively on January 1, 2018, as a result of which we included restricted cash amounts in our beginning and ending cash balances on the statement of cash flows and included a disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statement of cash flows.statements.
New Accounting Standards Issued, But Not Yet Adopted

In February 2016, the FASBFinancial Accounting Standards Board ("FASB") issued rules requiring lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers which is forissuers. During the second quarter of 2020, this adoption date was further delayed by FASB until fiscal years beginning after December 15, 2019,2021, including interim periods within those fiscal years. We are currently identifying our lease population in accordance with the new lease standard. We expect the adoption of these rules to primarily impactincrease other assets and other liabilities on our balance sheet and do not expect a materialwe are currently evaluating the impact on our consolidated results of operations.

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During 2016,BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
In December 2019, the FASB issued rules clarifyingwhich simplify the new revenue recognition standard issued in 2014. The new rules are intended to improve and converge the financial reporting requirementsaccounting for revenue from contracts with customers. We areincome taxes. As an emerging growth company, andwe have elected to delay the adoption of these rules until they are applicable to non-SEC issuers which is for fiscal years beginning after December 31, 2018.15, 2021, including interim periods within those fiscal years. We are currently evaluating the impact of these rules on our consolidated financial statements.
In March 2020, the adoptionFASB issued rules providing optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by the reference rate reform, if certain criteria are met. The optional expedient for contract modifications applies to contract modifications that replace a reference rate affected by the reference rate reform, such as the London Interbank Offered Rate (“LIBOR”). Entities may elect to apply the amendments for contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 through December 31, 2022. We are currently evaluating the impact of these rules on our consolidated financial statements and related disclosures.statements.
Note 2 - Emergence from Voluntary Reorganization under Chapter 11
On December 16, 2013, an affiliate of LINN Energy, LinnCo, LLC (“LinnCo”), acquired all the outstanding common shares of Berry Petroleum Company and contributed Berry Petroleum Company to LINN Energy in exchange for LINN Energy units. In connection with its acquisition by LINN Energy, Berry Petroleum Company was converted from a Delaware corporation into a Delaware limited liability company and changed its name to “Berry Petroleum Company, LLC.” Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, became Berry LLC’s sole member.

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




On May 11, 2016 (the “Petition Date”), the LINN entities ("LINN Entities") and, consequently, Berry LLC (collectively, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 (“Chapter 11”) of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040 (collectively, the “Chapter 11 Proceedings”). During the pendancy of the Chapter 11 Proceedings, the debtors in the Chapter 11 Proceedings (the “Debtors”), operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
In December 2016, Berry LLC and Linn Acquisition Company, LLC, on the one hand, and LINN Energy and its other affiliated debtors, on the other hand, filed separate plans of reorganization with the Bankruptcy Court. The “Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC” (the “Plan”) was filed on December 13, 2016. On January 27, 2017, the Bankruptcy Court entered its confirmation order (the “Confirmation Order”) approving and confirming the Plan.
On February 28, 2017, the Plan became effective and was implemented in accordance with its terms. Among other transactions, Linn Acquisition Company, LLC transferred 100% of Berry LLC’s outstanding membership interests to Berry Corp. As a result, Berry LLC emerged from bankruptcy as a wholly-owned subsidiary of Berry Corp., separate from LINN Energy and its affiliates, effective February 28, 2017 (the “Effective Date”).
Plan of Reorganization
On the Effective Date, the Company consummated the following reorganization transactions in accordance with the Plan:
Linn Acquisition Company, LLC transferred 100% of the outstanding membership interests in Berry LLC to Berry Corp. pursuant to an assignment agreement, dated February 28, 2017 between Linn Acquisition Company, LLC and Berry Corp. (the “Assignment Agreement”). Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.
The holders of claims under the Company’s Second Amended and Restated Credit Agreement, dated November 15, 2010, by and among Berry LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and certain lenders, (as amended, the “Pre-Emergence Credit Facility”), received (i) their pro rata share of a cash paydown and (ii) pro rata participation in the new facility (the “Emergence Credit Facility”). As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceled and the agreements governing these obligations were terminated.
Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A, as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments.
The holders of Berry LLC’s 6.75% senior notes due 2020, issued by Berry LLC pursuant to a Second Supplemental Indenture, dated November 1, 2010, and 6.375% senior notes due 2022, issued by Berry LLC pursuant to a Third Supplemental Indenture, dated March 9, 2012 (collectively, the “Unsecured Notes”), received a right to their pro rata share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”) and (ii) specified rights to participate in a two-tranche offering of rights to purchase Series A Preferred Stock at an aggregate purchase price of $335 million (as further defined in the Plan, the “Berry Rights Offerings”). As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.
The holders of unsecured claims against Berry LLC, other than the Unsecured Notes, (the “Unsecured Claims”) received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. As a result, all outstanding obligations under the Unsecured Notes and the indentures governing such obligations were canceled and the obligations arising from the Unsecured Claims were extinguished.
Berry LLC settled all intercompany claims against LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy which Berry LLC has fully-reserved.





BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018





Liabilities Subject to Compromise

Liabilities subject to compromise decreased from approximately $35 million as of December 31, 2017 to approximately $20 million as of June 30, 2018. Activity for our liabilities subject to compromise for the six months ended June 30, 2018 included the return of $9 million in undistributed funds from restricted cash, approximately $6 million in settlement payments to general unsecured creditors and other payments of professional fees incurred to settle these claims.
Reorganization Items, Net
We have incurred and continue to incur expenses associated with the reorganization. Reorganization items, net represent costs and gains directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined. The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations:
 Berry Corp. (Successor)Berry LLC (Predecessor)
 Three Months
Ended		Three Months EndedSix Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017June 30, 2018June 30, 2017February 28, 2017
 (in thousands)  
Return of undistributed funds from Cash Distribution Pool$—
$—
$9,000
$—
$—
Refund of pre-emergence prepaid costs—
—
579
—
—
Gain on settlement of liabilities subject to compromise—
—
—
—
421,774
Fresh start valuation adjustments—
—
—
—
(920,699)
Legal and other professional advisory fees(1,178)713
(1,802)112
(19,481)
Gain on resolution of pre-emergence liabilities1,634
—
1,634
—
—
Other—
—
—
(705)10,686
Reorganization items, net$456
$713
$9,411
$(593)$(507,720)

In August 2018, we received an additional return of undistributed funds from the Cash Distribution Pool of approximately $14 million.


BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




Note 3 - 2—Debt
The following table summarizes our outstanding debt:
September 30,
2020		December 31, 2019Interest RateMaturitySecurity
(in thousands)
RBL Facility$0 $1,850 
variable rates
4.0% (2020) and 5.5% (2019), respectively
July 29, 2022Mortgage on 85% of Present Value of proven oil and gas reserves and lien on certain other assets
2026 Notes400,000 400,000 7.0%February 15, 2026Unsecured
Long-Term Debt - Principal Amount400,000 401,850 
Less: Debt Issuance Costs(6,781)(7,531)
Long-Term Debt, net$393,219 $394,319 
 (in thousands)   
 June 30, 2018December 31, 2017Interest RateMaturitySecurity
RBL Facility$66,000
$379,000
variable rates of 4.5% (2018) and 4.8% (2017), respectivelyJune 29, 2022Mortgage on 85% of Present Value of proven oil and gas reserves
2026 Notes400,000
—
7.00%February 15, 2026Unsecured
Long-Term Debt- Principal Amount466,000
379,000
   
Less: Debt Issuance Costs(8,667)—
   
Long-Term Debt, net$457,333
$379,000
   
Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At JuneSeptember 30, 20182020 and December 31, 2017,2019, debt issuance costs for the RBL Facility (as defined below) reported in "non current assets"“other noncurrent assets” on the balance sheet were approximately $18$8 million and $21$11 million net of amortization, respectively. The amortization ofAt September 30, 2020 and December 31, 2019, debt issuance costs, is presentednet of amortization, for the unsecured notes due February 2026 (the “2026 Notes”) reported in interestLong-Term Debt, net were approximately $7 million and $8 million, respectively.
For each of the three month periods ended September 30, 2020 and September 30, 2019, the amortization expense onfor both the RBL Facility and 2026 Notes was approximately $1 million and was included in “interest expense” in the condensed consolidated statements of operations. For each of the nine month periods ended September 30, 2020 and September 30, 2019, the amortization expense for both the RBL Facility and 2026 Notes was approximately $4 million.
Fair Value
Our debt is recorded at the carrying amount on the balance sheets. The carrying amount of the RBL Facility approximates fair value because the interest rates are variable and reflect market rates. The fair value of the 2026 senior unsecured notesNotes was approximately $408$314 million and $376 million at JuneSeptember 30, 2018.2020 and December 31, 2019, respectively.
Credit Facilities
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The RBL Facility
On July 31, 2017, we entered into a credit agreement (“RBL Facility”), with Wells Fargo Bank, N.A. as administrative agent and certain lendersthat provided for a revolving loan with up to $1.5 billion of commitments,commitment, subject to a reserves-based borrowing base. In connection with the issuance of the 2026 Notes, the RBL Facilityreserve borrowing base was set at $400 million which incorporated a $100 million reduction, or 25% of the face value of the 2026 Notes (as defined below)(“RBL Facility”). In March 2018,June 2020, we completed aour scheduled semi-annual borrowing base redetermination under our RBL Facility, which reaffirmed ourresulted in a decrease to the borrowing base atto $200 million from $500 million; decrease to the elected commitments to $200 million from $400 million with an elected commitment feature that allows us to increasemillion; limitation on the maximum borrowing availability under the RBL Facility to $575$150 million until the next semi annual borrowing base redetermination (scheduled to occur in November 2020); the implementation of certain anti-cash hoarding provisions, including the requirement to repay outstanding loans on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $30 million; and further limits dividends and share repurchases. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with lender approval.the RBL Facility terms. Borrowing base redeterminations generally become effective each May and November, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations.
AsThe RBL Facility contains customary events of June 30, 2018,default and remedies for credit facilities of a similar nature. If we do not comply with the financial performanceand other covenants under ourin the RBL Facility, werethe lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral.
The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a leverage ratioLeverage Ratio of no more than 4.004.0 to 1.001.0 and (ii) a current ratioCurrent Ratio of at least 1.001.0 to 1.00. At June1.0. The RBL Facility also contains customary restrictions. As of September 30, 2018,2020, our actual ratiosLeverage Ratio and Current Ratio were 2.631.5 to 1.001.0 and 3.182.7 to 1.00,1.0, respectively. In addition, the RBL Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants under the RBL Facility as of JuneSeptember 30, 2018.2020.
As of JuneSeptember 30, 2018,2020, we had 0 borrowings outstanding, $7 million in letters of credit outstanding, and approximately $327$143 million of available borrowingborrowings capacity under the RBL Facility.
AsBond Repurchase Program
In February 2020, our Board of June 30, 2018Directors adopted a program to spend up to $75 million for the opportunistic repurchase of our 2026 Notes. The manner, timing and December 31, 2017, we had lettersamount of creditany purchases will be determined based on our evaluation of market conditions, compliance with outstanding of approximately $7 million and $21 million, respectively, under our revolving credit facilities. These letters of credit were issued to support ordinary course of business marketing, insurance, regulatoryagreements and other matters.factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any bonds under this program.
Corporate Organization
Berry Corp., as Berry LLC’s parent company, has no independent assets or operations. Any guarantees of potential future registered debt securities by Berry Corp. or Berry LLC would be full and unconditional. Berry Corp. and Berry LLC currently do not have any other subsidiaries. In July and August 2018, we paid down approximately $105 million onaddition, there are no significant restrictions upon the RBL Facility from the net proceeds we received in the IPOability of our common stock (see Note 6). On August 20, 2018, we had approximately $388 million of available borrowing capacityBerry LLC to distribute funds to Berry Corp. by distribution or loan other than under the RBL Facility. None of the assets of Berry Corp. or Berry LLC represent restricted net assets.
The RBL Facility permits Berry LLC to make distributions to Berry Corp. so long as both before and approximately $36 millionafter giving pro forma effect to such distribution no default or borrowing base deficiency exists, availability equals or exceeds 20% of cash on hand.
Senior Unsecured Notes Offering
In February 2018, we completedthe then effective borrowing base, and Berry Corp. demonstrates a private issuance of $400 million in aggregate principal amount of 7.00% senior unsecured notes due 2026 (the “2026 Notes”), which resulted in net proceedspro forma leverage ratio less than or equal to us of approximately $391 million after2.5 to 1.0. The conditions are currently met with significant margin.

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BERRY PETROLEUM CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2018(Unaudited)




deducting expenses and the initial purchasers’ discount. We used a portion of the net proceeds from the issuance of the 2026 Notes to repay borrowings under the RBL Facility and used the remainder for general corporate purposes.
Note 4 - 3—Derivatives
We have hedgedutilize derivatives, such as swaps, puts and calls, to hedge a portion of our forecasted oil and gas production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices, and wewhich addresses our market risk. We target covering our operating expenses and a majority of our fixed charges, including capital for sustained production levels, interest and dividends, with the oil and gas sales hedges for a period of up to two years out. We have also hedgedAdditionally, we target fixing the price for a large portion of our exposurenatural gas purchases used in our steam operations for up to differentials between Brent and WTI.two years. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations, thatwhich we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions.
Our current hedge positions consist of primarilyFor fixed-price oil swap contracts and deferred premiumgas sales swaps, we are the seller, so we make settlement payments for prices above the indicated weighted-average price per barrel and per MMBtu, respectively, and receive settlement payments for prices below the indicated weighted-average price per barrel and per MMBtu, respectively.
For our purchased put options, though in the past we have also used collars and three-way collars and hedged our exposure to natural gas and natural gas liquids (NGL) price changes. We enter into these transactions with respect to a portion of our projected production to provide an economic hedge against the risk related to the future commodity prices received. We do not enter into derivative contracts for speculative trading purposes. We did not designate any of our contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.
As part of our hedging program, we entered into a number of derivative transactions that resulted in the following crude oil contracts as of June 30, 2018:
 Q3 2018Q4 2018FY 2019FY 2020
Sold Oil Calls (ICE Brent):    
  Hedged volume (MBbls)186
—
—
—
  Weighted average price ($/Bbl)$81.67
$—
$—
$—
 Purchased Put Options (ICE Brent):    
  Hedged volume (MBbls)—
—
2,835
455
  Weighted average price ($/Bbl)—
$—
$65.00
$65.00
Fixed Price Swaps (ICE Brent):    
  Hedged volume (MBbls)966
966
900
—
  Weighted average price ($/Bbl)$75.13
$75.13
$75.66
$—
Oil basis differential positions:    
ICE Brent-NYMEX WTI basis swaps    
  Hedged volume (MBbls)92
92
182.5
—
  Weighted average price ($/Bbl)$1.29
$1.29
$1.29
$—
We earn a premium on our sold oil calls, at the time of sale. We make netwe would receive settlement payments for prices above the indicated weighted-average price per barrel of Brent. If the calls expire unexercised, no payments are received.
For our purchased puts,fixed-price gas purchase swaps, we would receiveare the buyer so we make settlement payments for prices below the indicated weighted-average price per barrel of Brent. The purchased put options contain deferred premiums of approximately $17.9 millionMMBtu and are reflected in the mark-to-market valuation of the derivatives on the balance sheet at June 30, 2018. The premiums will be payable in conjunction with the monthly settlements of these contracts and thus have been deferred until payments begin in 2019.
For fixed-price swaps, we makereceive settlement payments for prices above the indicated weighted-average price per barrelMMBtu.
We use oil and gas swaps and puts to protect our sales against decreases in oil and gas prices. We also use swaps to protect our natural gas purchases against increases in prices. We do not enter into derivative contracts for speculative trading purposes and have not accounted for our derivatives as cash-flow or fair-value hedges. The changes in fair value of Brentthese instruments are recorded in current earnings. Gains (losses) on oil and receive settlement paymentsgas sales hedges are classified in the revenues and other section of the statement of operations, while natural gas purchase hedges are included in expenses and other section of the statement of operations.
As of September 30, 2020, we had the following crude oil production and gas purchases hedges.
Q4 20201H 20212H 2021
Fixed Price Oil Swaps (Brent):
  Hedged volume (MBbls)2,208 3,438 2,084 
  Weighted-average price ($/Bbl)$59.85 $45.82 $46.17 
Purchased Oil Calls Options (Brent):
Hedged volume (MBbls)276 0 0 
Weighted-average price ($/Bbl)$65.00 $0 $0 
Fixed Price Gas Purchase Swaps (Kern, Delivered):
  Hedged volume (MMBtu)5,060,000 9,045,000 5,535,000 
  Weighted-average price ($/MMBtu)$2.76 $2.71 $2.73 
Fixed Price Gas Purchase Swaps (SoCal Citygate):
  Hedged volume (MMBtu)155,000 0 0 
  Weighted-average price ($/MMBtu)$3.80 $0 $0 
In October 2020, we added 12,500 MMBtu/d of fixed price gas sales swaps at an average price of $2.96, indexed to Northwest Pipeline Rocky Mountains and CIG, for prices below the indicated weighted-average price per barrel of Brent.period January 1, 2021 through December 31, 2021.

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BERRY PETROLEUM CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2018(Unaudited)




For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated weighted-average price per barrel and receive settlement payments if the difference between Brent and WTI is below the indicated weighted-average price per barrel.

Our commodity derivatives are measured at fair value using industry-standard models with various inputs including publicly available underlying commodity prices and forward prices,curves, and all are classified as Level 2 in the required fair value hierarchy for the periods presented. These commodity derivatives are subject to counterparty netting. The following tables present the fair values (gross and net) of our outstanding derivatives as of JuneSeptember 30, 20182020 and December 31, 2017:2019:
September 30, 2020
Balance Sheet
Classification		Gross Amounts
Recognized at Fair Value		Gross Amounts Offset
in the Balance Sheet		Net Fair Value Presented 
on the Balance Sheet
(in thousands)
Assets:
  Commodity ContractsCurrent assets$60,307 $(2,649)$57,658 
  Commodity ContractsNon-current assets2,703 (693)2,011 
Liabilities:
  Commodity ContractsCurrent liabilities(2,986)2,649 (337)
  Commodity ContractsNon-current liabilities(1,871)693 (1,179)
Total derivatives$58,153 $— $58,153 

Berry Corp. (Successor) December 31, 2019
June 30, 2018 Balance Sheet
Classification		Gross Amounts
Recognized at Fair Value		Gross Amounts Offset
in the Balance Sheet		Net Fair Value Presented 
on the Balance Sheet
Balance Sheet
Classification		Gross Amounts
Recognized at
Fair Value		Gross Amounts
Offset in the
Balance Sheet		Net Fair Value
Presented in the
Balance Sheet		 (in thousands)
(in thousands)
Liabilities  
Assets:Assets:
Commodity Contracts Commodity ContractsCurrent assets$17,799 $(8,633)$9,166 
Commodity Contracts Commodity ContractsNon-current assets773 (248)525 
Liabilities:Liabilities:
Commodity ContractsCurrent liabilities$(11,447)$—
$(11,447) Commodity ContractsCurrent liabilities(13,450)8,633 (4,817)
Commodity ContractsNon-current liabilities(3,563)—
(3,563) Commodity ContractsNon-current liabilities(389)248 (141)
Total derivatives $(15,010)$—
$(15,010)Total derivatives$4,733 $— $4,733 

By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We do not receive collateral from our counterparties.


 Berry Corp. (Successor)
 December 31, 2017
 Balance Sheet
Classification		Gross Amounts
Recognized at
Fair Value		Gross Amounts
Offset in the
Balance Sheet		Net Fair Value
Presented in the
Balance Sheet
 (in thousands)
Liabilities    
  Commodity ContractsCurrent liabilities$(49,949)$—
$(49,949)
  Commodity ContractsNon-current liabilities(25,332)—
(25,332)
Total derivatives $(75,281)$—
$(75,281)


We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In May 2018, we electedaddition, our RBL Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates that have margin call requirements, that otherwise require us to terminate outstanding commodity derivative contracts for all WTI oil swaps and certain WTI/Brent basis swaps for July 2018 through December 2019 and all WTI oil sold call options for July 2018 through June 2020. Termination costs totaled approximately $127 million and were calculated inprovide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standards & Poor’s or Moody’s, respectively. In accordance with a bilateral agreement onour standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives which partially mitigates the cost of elective termination included in these derivative contracts; the present value of the contracts using the forward price curve as of the date termination was elected. No penalties were charged as a result of the elective termination. Concurrently, Berry Corp. entered into commodity derivative contracts consisting of Brent oil swaps for July 2018 through March 2019 and Brent oil purchased put options for January 2019 through March 2020. These Brent oil swaps hedge 1.8 MMBbls in 2018 and 0.9 MMBbls in 2019 at a weighted average price of $75.66. These Brent oil purchased put options provide a weighted-average price floor of $65.00 for 2.8 MMBbls in 2019 and 0.5 MMBbls in 2020. We effected these transactions to move from a WTI-based position to a Brent-based position as well as bring our hedged pricing more in line with current market pricing.counterparty nonperformance risk.


BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018





Note 5 - 4—Lawsuits, Claims, Commitments and Contingencies
In the normal course of business, we, or our subsidiary, are the subject of, or party to, lawsuits, environmentalpending or threatened legal proceedings, contingencies and other claims and other contingenciescommitments involving a variety of matters that seek, or may seek, among
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civilfines and penalties, remediation costs, or injunctive or declaratory relief.
On May 11, 2016 our predecessor company filed the Chapter 11 Proceeding. Our bankruptcy case was jointly administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding. On the Effective Date the plan became effective and was implemented. The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims. For further information, see Note 2.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at JuneSeptember 30, 20182020 and December 31, 2017.2019. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.
We, have certain commitments under contracts, including purchase commitments for goods and services. At June 30, 2018, purchase obligations of approximately $13 million included a commitment to invest at least $9 million to construct a new access road in connection with our Piceance assets or provide access to an existing road or to pay 50% of the difference between $12 million and the actual amount spent on such access road construction prior to the end of 2019. If we do not obtain extensions for the road obligation, provide access to an existing road or construct a new access road, we may trigger the payment obligation which, if we were unable to negotiate resolution, would reduce our capital available for investment. Also, as of June 30, 2018, we had entered into agreements to purchase natural gas for our operations in 2018 for approximately $7 million.
We, or our subsidiary, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of JuneSeptember 30, 2018,2020, we are not aware of material indemnity claims pending or threatened against us.
We have certain commitments under contracts, including purchase commitments for goods and services. Prior to our 2017 emergence, Berry entered into operating lease agreements mainly for office space. Lease payments are generally expensed as part of generala Carry and administrative expenses. AtEarning Agreement with Encana, effective June 30, 2018, future net minimum lease payments for non-cancelable operating leases (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance and maintenance expense) totaled:
 Amount
 (in thousands)
2018$676
20191,170
2020157
2021159
2022160
Thereafter36
Total minimum lease payments$2,358
  
Note 6- Equity
Initial Public Offering of Common Stock
In July, we completed our 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. The Company sold 10,497,849 shares and the selling stockholders sold 2,545,630

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




shares at a price of $14.00 per share. We used a portion of our proceeds to repurchase 1,802,196 shares of our common stock owned by Benefit Street Partners and Oaktree Capital Management. After giving effect to the IPO and the share repurchase, the number of shares of our common stock outstanding increased by 8,695,653. We and the selling stockholders have granted the underwriters the option to purchase up to an additional 1,534,895 shares and 421,626 shares of common stock, respectively, on the same terms and conditions set forth above.
The Company received approximately $136 million in net proceeds from the offering after deducting underwriting discounts and offering expenses payable by us. We did not receive any proceeds from the sale by the selling stockholders. We used approximately $24 million of the net proceeds to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the offering) from funds affiliated with Benefit Street Partners and Oaktree Capital Management.
Of the remaining approximately $112 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the $60 million we borrowed on the RBL Facility to make the payment to the holders of our Series A Preferred Stock7, 2006, in connection with our Piceance assets which, among other things, required us to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the conversionobligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of preferred stock to common stock.Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We usedwill defend the remainder for general corporate purposes.
In connection withmatter vigorously, however, given the IPO, eachuncertainty of litigation and the preliminary stage of the 37.7 million sharescase, among other things, at this time we cannot estimate the reasonable possible loss, if any, that may result from this action.
Note 5—Equity
Cash Dividends
Our Board of our Series A Preferred Stock was automatically converted into 1.05 shares of our common stock or 39.6 million shares in aggregate and the right to receive a cash payment of $1.75 ("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.
Shares Issued and Outstanding
As of July 31, 2018, there were 81,336,762 shares of common stock issued and outstanding including 167,889 common shares that have vested as of June 30, 2018 relating to the Company's Omnibus Incentive Plan. An additional 1,447,998 unvested restricted stock units and performance restricted stock units were outstanding under the Company's Omnibus Incentive Plan as of July 31, 2018. A further 7,080,000 common shares have been reserved for issuance to the general unsecured creditor group pending resolution of disputed claims.
In March 2018, the board of directors approved a cumulative paid-in-kind dividend on the Series A Preferred Stock for the periods through December 31, 2017. The cumulative dividend was 0.050907 per share and approximately 1,825,000 shares in total. Also in March 2018, the board approved a $0.158 per share, or approximately $5.6 million, cash dividend on the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the payments were to stockholders of record as of March 15, 2018. In May 2018 the board of directors approved a $0.15 per share, or approximately $5.6 million cash dividend, on the Series A Preferred Stock for the quarter ended June 30, 2018. The payment was to stockholders of record as of June 7, 2018. In July 2018, all shares our of Series A Preferred Stock, approximately 37.7 million in total, were converted to approximately 39.6 million common shares and, as a result, there were no shares of our Series A Preferred Stock outstanding following the IPO.
On August 21, 2018, our board of directorsDirectors approved a $0.12 per share quarterly cash dividend on our common stock onfor the first quarter of 2020, which we paid in April 2020. In April 2020, in connection with the current low oil price environment, we temporarily suspended our quarterly dividend until oil prices recover.
Stock Repurchase Program
In December 2018, our Board of Directors adopted a pro-rata basis fromprogram for the dateopportunistic repurchase of up to $100 million of our IPO through September 30, 2018, which will result in a paymentcommon stock. Based on the Board’s evaluation of $0.09 per share.
Purchase of Common Stock
In connection with our IPO, we entered into stock purchase agreements with funds affiliated with each of Benefit Street Partners and Oaktree Capital Management pursuant to which we purchased an aggregate of 1,802,196 shares ofmarket conditions for our common stock at that time, they authorized initial repurchases of up to $50 million under the program. The Company repurchased a price equal tototal of 5,057,682 shares under the net proceeds per share received fromstock repurchase program for approximately $50 million as of December 31, 2019. In February 2020, the IPOBoard of Directors authorized the repurchase of the remaining $50 million of our common$100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock before expenses. The stock purchase agreementprice, compliance with funds affiliated with Benefit Street Partners requires usoutstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase additional shares during any period or at the same price if the underwriters exercise their option to purchase additionalall. Any shares in the IPO.
Treasury Stock Purchase
In March and April 2018, we entered into settlement agreements with two general unsecured creditors from our bankruptcy process. As a result, we paid approximately $20 million to purchase their claims to our common stock that we have reflected as treasury stock. We do not yet know the final amount of shares out of the 7,080,000 set aside that we will issue to third parties with respect to the unsecured claims. When all unsecured claims are settled, weacquired will be able to assign a share count toavailable for general corporate purposes. For the treasury stock. See Note 2nine months ended September 30, 2020, we did 0t repurchase any shares under "Plan of Reorganization" and Note 11 for further discussion of the common shares set aside to settle claims.stock repurchase program.

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




Stock-Based Compensation

In July 2018, we became a public company and our stock began trading onMarch 2020, the NASDAQ Global Select Market. As a result, the estimateCompany granted awards of the fair value1,817,656 shares of our stock-based compensation awards granted will no longer be based on complex models using inputs and assumptions but will be based on the price of our stock at the date of grant.
On June 27, 2018, our board of directors adopted the Berry Petroleum Corporation 2017 Omnibus Incentive Plan, as amended and restated (our “Restated Incentive Plan”). This plan constitutes an amendment and restatement of the plan as in effect immediately prior to the adoption of the Restated Incentive Plan (the "Prior Plan"). The Prior Plan constituted an amendment and restatement of the plan originally adopted as of June 15, 2017 (the "2017 Plan"). The Restated Incentive Plan provides for the grant, from time to time, at the discretion of the board of directors or a committee thereof, of stock options, stock appreciation rights ("SARs"), restricted stock, restricted stock units stock awards, dividend equivalents, other stock-based awards, cash awards(“RSUs”), which will vest annually in equal amounts over three years and substitute awards. The maximum number of shares of common stock that may be issued pursuant to an award under the Restated Incentive Plan is 10,000,000 inclusive of the number of shares of common stock previously issued pursuant to awards granted under the Prior Plan or the 2017 Plan. The maximum number of shares remaining that may be issued is approximately 8.3 million.
Included in lease operating expenses and general and administrative expenses is stock-based compensation expense of $44,000 and $1.3 million, respectively, for the three months ended June 30, 2018, and $67,000 and $2.3 million, respectively, for the six months ended June 30, 2018. For the three and six months ended June 30, 2017, including the successor and predecessor periods, there were no such expenses. For the six months ended June 30, 2018, stock-based compensation had an immaterial associated income tax benefit.
The table below summarizes the activity relating to1,278,877 performance-based restricted stock units ("RSUs"(“PSUs”) issued under the 2017 Plan during the six months ended June 30, 2018. The RSUs vest ratably over three years. Unrecognized compensation cost associated with the RSUs at June 30, 2018 is approximately $6.8 million, which will be recognized overcliff vest, if at all, at the end of a weighted averagethree year performance period of approximately two years.

subject to both an absolute total stockholder return (“Absolute TSR”) performance metric and a relative total stockholder return (“Relative TSR”)
11
 Number of sharesWeighted average Grant Date Fair Value
 (shares in thousands)
December 31, 2017683
$10.12
Granted205
$11.50
Vested(166)$11.68
Forfeited(26)$10.12
June 30, 2018696
$10.20


Table of Contents
BERRY PETROLEUM CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2018



(Unaudited)

performance metric, as further discussed and defined below. The fair value of these awards was approximately $32 million.
The table below summarizes the activity relatingRSUs awarded are solely time-based awards. The PSUs awarded include a market objective measured against both Absolute TSR and Relative TSR to the performance-based restricted stock units ("PRSUs"Vanguard World Fund - Vanguard Energy ETF index (the “Index”) issued underover the 2017 Planperformance period, assuming the reinvestment of dividends. Depending on the results achieved during the six months ended June 30, 2018. three-year performance period, the actual number of shares that a grant recipient receives at the end of the period may range from 0% to 200% of the PSUs granted.
The PRSUs vest iffair value of the Company'sPSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the Index over the performance periods. The expected volatility of the Company’s common stock price reaches certain levels over defined periodsat the date of time. Unrecognized compensation cost associatedgrant was estimated based on average volatility rates for the Company and selected guideline public companies. The dividend yield assumption was based on the then current annualized declared dividend. The risk-free interest rate assumption was based on observed interest rates consistent with the PRSUs at June 30, 2018 is approximately $3.8 million which will be recognized over a weighted-average period of approximately two years.approximate three-year performance measurement period.

 Number of sharesWeighted average Grant Date Fair Value
 (shares in thousands)
December 31, 2017622
$7.09
Granted132
$7.49
Vested—
$—
Forfeited(2)$7.09
June 30, 2018752
$7.11
Note 7 - Income taxes
Prior to the Effective Date, Berry LLC was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of Berry LLC. Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC in a taxable asset acquisition as part of the restructuring. Consequently, we are now taxed as a corporation and have no net operating loss carryforwards for the periods prior to February 28, 2017.
On December 22, 2017, the U.S. the Tax Cuts and Jobs Act (the “Act”) which made significant changes to the Internal Revenue Code of 1986, including lowering the maximum federal corporate rate from 35 percent to 21 percent and imposing limitations on the use of net operating losses arising in taxable years ending after December 31, 2017.  This was the key contributor to the decrease in our effective rate from 40% in the 2017 Successor periods to 16% and 17% in the three and six months ended June 30, 2018, respectively.  We anticipate earnings for fiscal year 2018, in part due to the termination and resetting of our hedge positions in May 2018. These earnings consequently allow for the release of our valuation allowance, described below, resulting in an effective tax rate less than the maximum federal and applicable state tax rate for the six months ended June 30, 2018.There were no current income taxes during the six months ended June 30, 2018

Our accounting for the U.S. Tax Reform Act is incomplete. As noted at year-end, however, we were able to reasonably estimate certain effects and, therefore, recorded provisional adjustments to income tax expense for the revaluation of deferred tax assets and liabilities from 35 percent to 21 percent associated with the reduction in the U.S. corporate income tax rate, and for a valuation allowance on certain deferred tax assets impacted by the Act. We have not revised any of the 2017 provisional estimates. Any subsequent adjustments to these amounts will be recorded to income tax expense in the quarter the analysis is complete.

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




Note 8 - 6—Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed ConsolidatedFinancial Statements of Cash Flows

Other current assets reported on the condensed consolidated balance sheets included the following:
September 30, 2020December 31, 2019
(in thousands)
Prepaid expenses$4,526 $4,577 
Materials and supplies11,731 10,544 
Oil inventories3,409 3,432 
Other652 846 
Total other current assets$20,318 $19,399 
 Berry Corp. (Successor)
 June 30, 2018December 31, 2017
 (in thousands)
Prepaid expenses$6,692
$6,901
Oil inventories, materials and supplies7,062
5,938
Other1,227
1,227
 $14,981
$14,066
The major classes of inventory were not material and therefore not stated separately. Other non-current assets at JuneSeptember 30, 20182020 and December 31, 2017,2019, included approximately $18$8 million and $20$11 million of deferred financing costs, net of amortization, respectively.
Accounts payable and accrued expenses on the condensed consolidated balance sheets included the following:

September 30, 2020December 31, 2019
(in thousands)
Accounts payable-trade$6,596 $13,986 
Accrued expenses45,841 57,078 
Royalties payable12,282 25,385 
Taxes other than income tax liability12,390 9,150 
Accrued interest3,500 10,500 
Dividends payable5 9,888 
Asset retirement obligation - current portion13,700 25,208 
Other923 616 
Total accounts payable and accrued expenses$95,237 $151,811 

We reclassified certain accrued expenses to accounts payable trade accounts for the prior period to conform to the current year presentation. These reclassifications had no impact on the financial statements.
The increase in the long-term portion of the asset retirement obligation from $124 million at December 31, 2019 to $136 million at September 30, 2020 was due to $7 million of accretion, $6 million of liabilities incurred and
12
 Berry Corp. (Successor)
 June 30, 2018December 31, 2017
 (in thousands)
Accounts payable-trade$10,698
$15,469
Accrued expenses57,531
34,359
Royalties payable18,811
25,793
Greenhouse gas liability5,732
10,446
Taxes other than income tax liability9,428
8,437
Accrued interest10,970
—
Other—
3,373
 $113,170
$97,877
BERRY PETROLEUM CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2018



(Unaudited)

reclassification of $12 million from the current to long-term portion due to changes in anticipated spending and regulatory requirements. These increases were partially offset by $12 million of liabilities settled during the period.

Other non-current liabilities at September 30, 2020 and December 31, 2019 included approximately $35 million and $33 million of greenhouse gas liability, respectively.
Supplemental Information on the Statement of Operations
For the three months ended September 30, 2020, other operating expense was $2 million and mainly consisted of excess abandonment costs and oil tank storage fees. For three months ended September 30, 2019 other operating income was $1 million and mainly consisted of proceeds from the sale of assets, partially offset by excess abandonment costs in 2019.
For the nine months ended September 30, 2020 and 2019 other operating expenses were $3 million and $4 million, respectively. These other operating expenses mainly consist of excess abandonment costs, oil tank storage fees, and drilling rig standby charges, partially offset by tax and other refunds in 2020 and excess abandonment costs in 2019.
Supplemental Cash Flow Information
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
Nine Months Ended
September 30,
20202019
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties$1,013 $8,474 
Supplemental Disclosures of Cash Payments (Receipts):
  Interest, net of amounts capitalized$29,962 $30,136 
  Income taxes$222 $0 
 Berry Corp.Berry LLC
 (Successor)(Predecessor)
 Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017February 28, 2017
 (in thousands) 
Supplemental Disclosures of Significant Non-Cash Investing Activities:   
  (Decrease) increase in accrued liabilities related to purchases of property and equipment$8,614
$1,172
$2,249
Supplemental Disclosures of Cash Payments/(Receipts):   
  Interest$3,298
$5,261
$8,057
  Income taxes$—
$1,168
$—
  Reorganization items, net$1,352
$(792)$11,838

The following table provides a reconciliation of Cash, Cash Equivalents and Restricted Cash as reported in the Consolidated Statements of Cash Flows to the line items within the Consolidated Balance Sheets:

 Berry Corp. (Successor)Berry LLC (Predecessor)
(in thousands)Six Months EndedFour Months EndedTwo Months Ended
Beginning of PeriodJune 30, 2018June 30, 2017February 28, 2017
Cash and cash equivalents$33,905
$32,049
$30,483
Restricted cash34,833
52,860
197,793
Restricted cash in other noncurrent assets—
125
128
Cash, cash equivalents and restricted cash$68,738
$85,034
$228,404
    
Ending of Period   
Cash and cash equivalents$3,600
$3,735
$32,049
Restricted cash19,710
38,908
52,860
Restricted cash in other noncurrent assets—
—
125
Cash, cash equivalents and restricted cash$23,310
$42,643
$85,034


Restricted cash is primarily associated with cash reserved to settle claims with the general unsecured creditors resulting from implementation of the Plan. Cash and cash equivalents consistsconsist primarily of highly liquid investments with original maturities of three months or less and are stated at cost, which approximates fair value. As part of our cash management system, we use a controlled disbursement account to fund cash distribution checks presented for payment by the holder. Checks issued but not yet presented to banks may result in overdraft balances for accounting purposes and have been included in "accounts payable and accrued expenses" in the condensed consolidated balance sheets, amounts are immaterial for these periods.
Note 9 - Certain Relationships and Related Party Transactions
In connection with our emergence from bankruptcy, we entered into agreements with certain of our affiliates and with parties who received shares of our common stock and Series A Preferred Stock in exchange for their claims.

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018





Transition Services and Separation Agreement (“TSSA”)
On the Effective Date, Berry LLC entered into the TSSA with LINN Energy and certain of its subsidiaries to facilitate the separation of Berry LLC’s operations from LINN Energy’s operations. Pursuant to the TSSA, (i) LINN Energy continued to provide, or cause to be provided, certain administrative, management, operating, and other services and support to the Company during a transitional period following the Effective Date (the “Transition Services”), (ii) the LINN Energy debtors and Berry LLC separated their previously combined enterprise and (iii) the LINN Energy debtors transferred to Berry LLC certain assets that relate to Berry LLC’s properties or its business, in each case under the terms and conditions specified in the TSSA.
Under the TSSA, Berry LLC reimbursed LINN Energy for any and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented, in connection with providing the Transition Services. Additionally, Berry LLC paid to LINN Energy a management fee equal to $6 million per month, prorated for partial months, during the period from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”) and $2.7 million per month, prorated for partial months, from the first day following the Transition Period through the last day of the second full calendar month thereafter (the “Accounting Period”). During the Accounting Period, the scope of the Transition Services was reduced to specified accounting and administrative functions. The Transition Period under the TSSA ended April 30, 2017, and the Accounting Period ended June 30, 2017.
For the four months ended June 30, 2017, we incurred management fee expenses of approximately $17 million under the TSSA. Since the agreement commenced on the Effective Date, no expenses were incurred for the period ended February 28, 2017.
Note 10 - Acquisitions and Divestitures

Chevron North Midway-Sunset Acquisition
In April 2018, we acquired from LINN Energy Holdings, LLC two leases on an aggregate of 214 acres and a lease option on 490 acres (the "Chevron North Midway-Sunset Acquisition") of land owned by Chevron U.S.A. in the north Midway-Sunset field immediately adjacent to assets we currently operate. We assumed a drilling commitment of approximately $34.5 million over a 5-year term and would assume a further minimum 40 well drilling commitment if we exercise our option; but otherwise we paid no consideration. Our drilling commitment will be tolled for a month for each consecutive 30-day period for which the posted price of WTI is less than $45 per barrel. This transaction is consistent with our business strategy to investigate areas beyond our known productive areas.
Note 11- 7—Earnings Per Share
The Predecessor was organized as a limited liability company and, as such, did not issue any stock. Accordingly, we have not presented earnings per share calculations for the predecessor company periods.

We calculate basic earnings (loss) per share by dividing net income (loss) available to common stockholders by the weighted averageweighted-average number of common shares outstanding duringfor each period.period presented. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, such as those shares contemplated by the Plan, are considered common shares outstanding and are included in the computation of net income (loss) per share. Accordingly,
The RSUs and PSUs are not a participating security as the 40 million shares of common stock contemplated bydividends are forfeitable. For the Plan, without regard to actual issuance dates,three and nine months ended September 30, 2020 0 incremental RSUs or PSUs were included in the computationdiluted EPS calculation as their effect was anti-dilutive under the “if converted” method. For the three and nine months ended September 30, 2019 we included 69,000 and 145,000 incremental RSUs in the diluted EPS calculation and 0 incremental PSUs were included in the EPS calculation due to their contingent nature.
13
BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
 Three Months Ended
September 30,		Nine Months Ended
September 30,
2020201920202019
 (in thousands except per share amounts)
Basic EPS calculation
Net (loss) income$(18,864)$52,649 $(199,065)$50,523 
Weighted-average shares of common stock outstanding79,879 80,982 79,776 81,703 
Basic (loss) earnings per share$(0.24)$0.65 $(2.50)$0.62 
Diluted EPS calculation
Net (loss) income$(18,864)$52,649 $(199,065)$50,523 
Weighted-average shares of common stock outstanding79,879 80,982 79,776 81,703 
Dilutive effect of potentially dilutive securities(1)
0 69 0 145 
Weighted-average common shares outstanding - diluted79,879 81,051 79,776 81,848 
Diluted (loss) earnings per share$(0.24)$0.65 $(2.50)$0.62 
__________
(1)    NaN potentially dilutive securities were included in computing diluted (loss) earnings per share for the three and sixnine months ended JuneSeptember 30, 2018,2020, because the three months ended June 30, 2017,effect of inclusion would have been anti-dilutive.
Note 8—Revenue Recognition
We account for revenue in accordance with the Accounting Standards Codification 606, Revenue from Contracts with Customers, which we adopted on January 1, 2019, using the modified retrospective method, which was applied to all contracts that were not completed as of that date. Prior period results were not adjusted and continue to be reported under the four months ended June 30, 2017.accounting standards in effect for the prior period. The actualnew standard did not affect the timing of our revenue recognition and did not impact net income; accordingly, we did not record an adjustment to the opening balance of retained earnings.
We adopted the practical expedient related to disclosing the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied at the end of the reporting period. The performance obligations that are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation.
We derive substantially all of our common stockrevenue from sales of oil, natural gas and natural gas liquids (“NGL”), with the remaining revenue generated from sales of electricity and marketing activities.
The following is a description of our principal activities from which we generate revenue. Revenues are recognized when a customer obtains control of promised goods or services, in an amount that will be issuedreflects the consideration we expect to receive in exchange for those goods or services.
Oil, Natural Gas and NGLs
We recognize revenue from the 7,080,000 shares reserved for Unsecured Claimssale of our oil, natural gas and includedNGL production when delivery has occurred and control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the 40 million shares above, cannot be known until all claims are settled, adjustments have been made based on the stock to be received by Unsecured Claims and claims under the Unsecured Notes and, the final number of shares of common stock to be received per dollar of Unsecured Claims, is known. However, while we do not yet know the final amount of shares that we will issueexpect to third parties,receive once we have entered into agreements in March and April 2018 that materially reduced that number.
The Series A Preferred Stock was not a participating security, therefore, we calculated diluted EPS usingare able to adequately estimate the “if-converted" method under which the preferred dividendsconsideration (i.e., when market prices are added back to the numerator and the convertible preferred stock is assumed to be converted at the beginning of the period. No incremental shares of Series A Preferred Stock were included in the diluted EPSknown). Our contracts with customers typically require payment within 30 days following invoicing.

14
BERRY PETROLEUM CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2018



(Unaudited)

Electricity Sales
calculation forThe electrical output of our cogeneration facilities that is not used in our operations is sold to the three and six months ended June 30, 2018, as their effect was antidilutiveCalifornia market based on market pricing, which includes capacity payments. The majority of the portion sold from 3 of our cogeneration facilities is sold under long-term contracts to 2 California utility companies, based on market pricing. Revenue is recognized over time when obligations under the “if-converted” method. However,terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the convertible preferred stock may potentially dilute basic earningselectricity. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per sharekilowatt hour and monthly rates vary based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the future.case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations.
In July 2018, all outstanding sharesMarketing Revenue
Marketing revenue primarily includes our activities associated with transporting and marketing third-party volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on the condensed consolidated statements of operations.
Disaggregated Revenue
As a result of adoption of this standard, we are now required to disclose the following information regarding revenue from contracts with customers on a disaggregated basis.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2020201920202019
(in thousands)
Oil sales$88,453 $136,710 $274,275 $392,325 
Natural gas sales3,347 4,067 9,549 14,867 
Natural gas liquids sales439 473 1,028 2,067 
Electricity sales8,744 7,460 19,089 22,553 
Marketing revenues330 413 1,075 1,657 
Other revenues0 40 53 261 
Revenues from contracts with customers101,313 149,163 305,069 433,730 
(Losses) gains on oil derivatives(11,564)45,509 157,398 7,546 
Total revenues and other$89,749 $194,672 $462,467 $441,276 
Note 9—Oil and Natural Gas Properties
We evaluate the impairment of our Series A Preferred Stock were converted to common sharesproved and unproved oil and natural gas properties whenever events or changes in connection withcircumstance indicate that a property’s carrying value may not be recoverable. If the IPO of our common stock (see Note 6).
 Berry Corp. (Successor)Berry LLC
 (Predecessor)
 Three Months EndedThree Months Ended Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017 June 30, 2018June 30, 2017February 28, 2017
 (in thousands except per share amounts)
Basic EPS calculation

 


Net income (loss)$(28,061)$12,120
 $(21,651)23,497
n/a
   less: Dividends on Series A Preferred Stock(5,650)(5,404) (11,301)(7,196)n/a
Net income (loss) available to common stockholders$(33,711)$6,716
 $(32,952)$16,301
n/a
Weighted-average shares of common stock outstanding33,010
32,920
 32,971
32,920
n/a
Shares of common stock distributable to holders of Unsecured Claims7,080
7,080
 7,080
7,080
n/a
Weighted-average common shares outstanding-basic40,090
40,000
 40,051
40,000
n/a
Basic Earnings (loss) per share$(0.84)$0.17
 $(0.82)$0.41
n/a
Diluted EPS calculation

    
Net income (loss)$(28,061)$12,120
 $(21,651)$23,497
n/a
  less: Dividends on Series A Preferred Stock(5,650)(5,404) (11,301)(7,196)n/a
Net income (loss) available to common stockholders$(33,711)$6,716
 $(32,952)$16,301
n/a
Weighted-average shares of common stock outstanding33,010
32,920
 32,971
32,920
n/a
Shares of common stock distributable to holders of Unsecured Claims7,080
7,080
 7,080
7,080
n/a
Weighted-average common shares outstanding-basic40,090
40,000
 40,051
40,000
n/a
Dilutive effect of potentially dilutive securities—
35,845
 —
35,845
n/a
Weighted-average common shares outstanding-diluted40,090
75,845
 40,051
75,845
n/a
Diluted Earnings (loss) per share$(0.84)$0.16
 $(0.82)$0.31
n/a

Note 12- Pro Forma Financial Data

PRO FORMA FINANCIAL DATA
The following unaudited pro forma condensed consolidated financial information of Berry Corp. gives effect to the issuancecarrying amount of the 2026 Notes,proved properties exceeds the Series A Preferred Stock Conversionestimated undiscounted future cash flows, we record an impairment charge to reduce the carrying values of proved properties to their estimated fair value. We estimate the fair values of proved properties using valuation techniques that consider the market approach for values from the recent sale of similar properties, if applicable, and the IPO includingincome approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the applicationfair values of net proceeds from the IPO. The unaudited pro forma condensed consolidated statementproved properties include estimates of: (i) reserves; (ii) future
15
The unaudited pro forma condensed consolidated statement of operations gives effect to the issuance of the 2026 Notes, the Series A Preferred Stock Conversion and the IPO, including the application of net proceeds from the offering, as if each had

Contents
BERRY PETROLEUM CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2018



(Unaudited)

operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These inputs require significant judgments and estimates by our management at the time of the valuation which can change significantly over time. The underlying commodity prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes will impact realizable prices. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement.
been completedWe evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of January 1, 2017.lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The unaudited pro forma condensed consolidated balance sheet gives effecttiming of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results.
As of March 31, 2020, we performed impairment tests with respect to our proved and unproved oil and gas properties as a result of significant declines in oil prices during the same transactionslatter part of the first quarter. These declines were driven by the uncertainty surrounding the outbreak of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19 (“COVID-19”) and other macroeconomic events such as if each had been completedthe geopolitical tensions between the Organization of Petroleum Exporting Countries ("OPEC") and Russia. The COVID-19 pandemic and related economic repercussions, coupled with actions taken by OPEC and other oil producing nations ("OPEC+"), created significant volatility, uncertainty, and turmoil in the oil and gas industry, which have negatively affected and are expected to continue to negatively affect our business. Low oil prices are expected to continue for some period as reflected by futures forward curves for crude.
Consequently, we recorded a non-cash pre-tax asset impairment charge of $289 million during the first quarter of 2020 on June 30, 2018.properties in Utah and certain California locations. We evaluated our proved properties in accordance with accounting guidance and fair value techniques utilizing the period-end forward price curve, as well as assessing projects we determine we would not pursue in the foreseeable future given the current environment. We believe our current plans and exploration and development efforts will allow us to realize the carrying value of our unproved property balance.
We did 0t record an impairment charge for the second or third quarter of 2020, as there were no triggering events.
Note 10—Income Taxes
The unaudited pro forma condensed consolidated financial statements are for informationalCOVID-19 pandemic and illustrative purposes onlyrelated economic repercussions, coupled with OPEC+ actions, created significant volatility, uncertainty, and turmoil in the oil and gas industry, which have negatively affected and are not necessarily indicative of the financial results that would have been had the events and transactions occurred on the dates assumed, nor are such financial statements necessarily indicative of the results of operations in future periods. The pro forma adjustments, as described in the accompanying notes, are based upon currently available information. The historical financial information has been adjusted to give effect to pro forma adjustments that are (i) directly attributable to the 2026 Notes, the Series A Preferred Stock Conversion, the IPO and the application of net proceeds from the offering, (ii) factually supportable, and (iii) expected to havecontinue to negatively affect our business. As a continuing impact onresult, after evaluating the Company’s consolidated results.
Background
2026 Notes
In February 2018,positive and negative evidence, we completeddetermined that it was more likely than not that a private issuance of $400 million in aggregate principal amount of 7.00% senior unsecured notes due 2026, which resulted in net proceeds of approximately $391 million after deducting expenses and the initial purchasers' discount. Alarge portion of these proceeds were used to repay borrowings under the RBL Facilityour tax credits recorded in 2019 and the remainder for general corporate purposes.
Series A Preferred Stock Conversion and Common Stock Offering
In connection withother deferred tax assets would not be realized. Accordingly, we recognized a valuation allowance on our IPO, we amended the Series A Preferred Stock certificate of designation to providedeferred tax assets for the automatic conversion of all outstanding shares of Series A Preferred Stock. Pursuant to the amendment, each outstanding share of Series A Preferred Stock was automatically converted into (i) 1.05 shares of common stock and (ii) the right to receive $1.75, minusquarter ended March 31, 2020 in the amount of any cash dividend paid by$51 million. As of the Companyquarter ended September 30, 2020, this amount is $56 million. The valuation allowance was the key contributor in the decrease in our effective tax rate from 28% for both the three and nine months ended September 30, 2019 to 10% and (1)% for the three and nine months ended September 30, 2020, respectively.
During the third quarter 2020, the Internal Revenue Service issued final regulations implementing interest expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed certain rules on such sharethe computation and limitation of Series A Preferred Stock in respect of any period commencinginterest expense amounts and are applicable for tax years beginning on or after April 1, 2018.
November 13, 2020. Early adoption is permitted for tax years beginning after December 31, 2017. We received approximately $136assessed the impact of these regulations being issued in the third quarter. As a result, we recognized the entirety of its $14 million of net proceeds from the IPO after deducting underwriting discounts and commissions and estimated offering expenses payable by us. Weuncertain tax benefits that were recorded as of December 31, 2019. The recognition of these uncertain tax benefits did not receive any proceeds fromaffect the saleeffective tax rate.
16













Contents
BERRY PETROLEUM CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 2018



(Unaudited)

Note 11—Acquisition
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
JUNE 30, 2018
(In May 2020, we acquired approximately 740 net acres in thousands)
 Berry Corp. (Successor) June 30, 2018Series A Preferred Stock Conversion and Common Stock Offering Berry Corp. (Successor) Pro Forma
ASSETS    
Current assets:    
Cash and cash equivalents$3,600
$—
(a) (b)$3,600
Accounts receivable, net56,860
  56,860
Restricted cash19,710
  19,710
Other current assets14,981
  14,981
Total current assets95,151
—
 95,151
Noncurrent assets:    
Oil and natural gas properties (successful efforts method)1,382,777
  1,382,777
Less accumulated depletion and amortization(88,548)
  (88,548)
 1,294,229
  1,294,229
Other property and equipment112,618
  112,618
Less accumulated depreciation(8,928)
  (8,928)
 103,690
  103,690
Other noncurrent assets22,086
  22,086
Total assets$1,515,156
$—
 $1,515,156
LIABILITIES AND EQUITY    
Current liabilities:    
Accounts payable and accrued
expenses		$113,170
$—
 $113,170
Derivative instruments11,447
  11,447
Liabilities subject to compromise19,710
  19,710
Total current liabilities144,327
—
 144,327
Noncurrent liabilities:    
Long-term debt457,333
(51,538)(a)405,795
Derivative instruments3,563
  3,563
Asset retirement obligation88,575
  88,575
Other noncurrent liabilities12,862
  12,862
     
Equity:    
Successor Series A Preferred Stock ($.001 par value, 250,000,000 shares authorized and 37,669,805 shares issued at June 30, 2018)335,000
(335,000)
(b)—
Successor common stock ($.001 par value, 750,000,000 shares authorized and 33,087,889 shares issued at June 30, 2018)33
48
(a)(b)81
Additional paid-in-capital536,188
386,490
(a)(b)922,678
Treasury stock, at cost(20,006)  (20,006)
Accumulated deficit(42,719)
  (42,719)
     
Total equity808,496
51,538
 860,034
Total liabilities and equity$1,515,156
$—
 $1,515,156

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR SIX MONTHS ENDED JUNE 30, 2018
(the North Midway Sunset Field for approximately $5 million. We paid $2 million at closing and the remaining $3 million was paid following our first production from this property, in thousands, except per share amounts)
 Berry Corp. (Successor) Six Months Ended June 30, 2018Issuance of 2026 NotesSeries A Preferred Stock Conversion and Common Stock Offering Berry Corp. (Successor) Pro Forma
Revenues and other:     
Oil, natural gas and NGL sales$263,010
   $263,010
Electricity sales11,423
   11,423
Gains (losses) on oil and natural gas derivatives(112,787)   (112,787)
Marketing revenues1,302
   1,302
Other revenues317
   317
 163,265
—
—
 163,265
Expenses and other:     
Lease operating expenses85,819
   85,819
Electricity generation expenses7,725
   7,725
Transportation expenses5,321
   5,321
Marketing expenses987
   987
General and administrative expenses24,466
   24,466
Depreciation, depletion and amortization40,288
   40,288
Taxes, other than income taxes16,972
   16,972
Gains on sale of assets and other, net123
   123
 181,701
—
—
 181,701
Other income and (expenses):     
Interest expense, net of amounts capitalized(16,951)(854) (c)(17,805)
Other, net(212)   (212)
 (17,163)(854)—
(c)(18,017)
Reorganization items, net9,411
   9,411
(Loss) income before income taxes(26,188)(854)—
(c)(27,042)
Income tax expense (benefit)(4,537)(147) (c)(4,684)
Net income (loss)   
(21,651)(707)—
 (22,358)
Dividends on Series A Preferred Stock(11,301) 11,301
(f)—
Net income (loss) available to common stockholders   
$(32,952)$(707)$11,301
 $(22,358)
Net income (loss) per share of common stock:     
Basic$(0.82)   $(0.26)
Diluted$(0.82)   $(0.26)
Weighted average common shares outstanding     
Basic (g)40,051
 46,333
(d) (e)86,384
Diluted (g)40,051
 46,333
(d) (e)86,384
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

1. Basisthe fourth quarter 2020. This property is adjacent to, and extends, our existing producing area and we have identified numerous future drilling locations. We believe additional opportunities exist in other productive reservoirs of Presentation

The accompanying unaudited pro forma condensed consolidated statementthis property. We also acquired all existing idle wells on this property, some of operations presentswhich we plan to return to production in the financial information of Berry Corp. assumingnear future as price and strategy dictate. We will plug and abandon the events and transactions had occurred on January 1, 2017. The consolidated balance sheet presents the information assuming the transactions occurred on June 30, 2018. Issuance of 2026 Notes Adjustments represent

BERRY PETROLEUM CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2018




adjustments to give effectremaining idle wells pursuant to the Company's issuance and net proceeds from the 2026 Notes to the condensed consolidated statement of operations asCalifornia Idle Well Management Program. We recorded a $6 million liability for asset retirement obligations of the date assumed. Series A Preferred Stock Conversion and Common Stock Offering Adjustments represent adjustments to give effect to the conversionexisting wells on this property.
17

2. Pro Forma Balance Sheet Adjustments

(a) Reflects the issuance of 8,695,653 additional net shares of common stock in the offering, the receipt of approximately $112 million of net proceeds, after the repurchase of 1,802,196 shares for approximately $24 million, from funds affiliated with Benefit Street Partners and Oaktree Capital Management in connection with the IPO and the usage of a portion of the net proceeds to pay down the outstanding balance on the RBL Facility. The number of shares and net proceeds does not include a number of shares issued by us equal to the number of shares purchased by us from funds affiliated with Benefit Street Partners and Oaktree Capital Management in connection with the IPO.

(b) Reflects the conversion of the outstanding shares of Series A Preferred Stock into (1) approximately 39.6 million shares of common stock and (2) the cash payment from the IPO net proceeds of $1.60 on each pre-conversion share of Series A Preferred Stock, or approximately $60 million.

3. Pro Forma Statement of Operations Adjustments

Issuance of 2026 Notes Adjustments
(c) The issuance of the 2026 Notes was assumed to have occurred on January 1, 2017 for pro forma purposes and to have resulted in net proceeds of $391 million. As a result, borrowings under the RBL Facility would not have been necessary during this period.

The Company calculated the pro forma adjustment to increase interest expense as a result of the higher interest rate on the 2026 Notes and reversing the interest expense and other fees associated with the RBL Facility for the six months ended June 30, 2018 as follows:
(in thousands) 
Reversal of interest expense, unused fee and LOC fee on the RBL Facility$(3,251)
Reversal of 2026 Notes interest expense(10,970)
Pro Forma- RBL Facility letter of credit fee ($7.1 million outstanding at 2.625%)93
Pro Forma-RBL Facility unused availability fee ($393 million availability at 0.5%)982
Pro Forma 2026 Notes interest expense.14,000
Pro Forma adjustment to increase interest expense$854

The effective tax rate applied to the increased interest expense was 17.3% for the six months ended June 30, 2018.

Series A Preferred Stock Conversion and Common Stock Offering Adjustments

(d) Reflects basic and diluted income per common share giving effect to the issuance of 8,695,653 shares of common stock in the IPO, assuming the IPO occurred January 1, 2017. The number of shares and net proceeds does not include shares purchased from the selling stockholders in the IPO or a number of shares issued by us equal to the number of shares purchased by us from funds affiliated with Benefit Street Partners and Oaktree Capital Management in connection with the IPO.

(e) Reflects the conversion of the outstanding shares of Series A Preferred Stock into approximately37.7 million shares of common stock, assumed to occur on January 1, 2017.

(f) Reflects the effect of reversing the Series A Preferred Stock dividends, assuming the IPO and the Series A Preferred Stock Conversion occurred January 1, 2017.

(g) Share count includes 7 million shares reserved for issuance to the general unsecured creditors resulting from the bankruptcy process.

Item 2.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with theour interim unaudited consolidated financial statements and related notes presented in this Quarterly Report on formForm 10-Q, as well as our audited consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2017 included in2019 (the “Annual Report”) filed with the prospectus.Securities and Exchange Commission (“SEC”). When we use the terms “we,“we,” “us,“us,” “our,“our,”“Berry,” the “Company”“Company” or similar words unless the context otherwise requires, on or prior to the Effective Date (see below),in this report, we are referring to, as the context may require, (i) Berry Corporation (bry) (formerly known as Berry Petroleum Corporation, and also referred to herein as ���Berry Corp.”) together with its wholly owned subsidiary, Berry Petroleum, LLC (also referred to herein as “Berry LLC our predecessor company and following February 28, 2017, the effective date ("Effective Date"”) of the Amended Joint Chapter 11 Plan of Linn Acquisition Company, LLC ("Linn Acquisition") and us (the "Plan"), we are referring toor (ii) either Berry Corp. and its subsidiary,or Berry LLC, together, the successor company, as applicable.LLC.
Our Company
We are a California-basedwestern United States independent upstream energy company engaged primarilywith a focus on onshore, low geologic risk, long-lived, oil reserves in conventional reservoirs.
In the aggregate, our assets are characterized by high oil content. Most of our assets are located in the development and production of conventional oil reserves located onshoreoil-rich reservoirs in the western United States. Our long-lived,San Joaquin basin of California, which has more than 150 years of production history and substantial remaining oil in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics are well understood, leading to predictable, repeatable, low geological risk and high margin asset base is uniquely positionedlow-cost development opportunities. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to support our objectivesunconventional resource plays. We also have assets in the low-cost, oil-rich reservoirs in the Uinta basin of generating top-tier corporate-level returnsUtah and positive free cash flow through commodity price cycles.low geologic risk, natural gas resource plays in the Piceance basin in Colorado. We believe that executingsuccessful execution of our strategy across our low-declining production base and extensive inventory of identified drilling locations willshould result in our ability, in appropriate oil price environments, to return capital to our stockholders and demonstrate long-term, capital efficient, consistent, and predictable production growth while living within “Levered Free Cash Flow” (a non-GAAP financial measure discussed under “How We Plan and Evaluate Operations” in this report).
We have a progressive approach to evolving and growing the business in today's dynamic oil and gas industry. Our strategy includes proactively engaging the many forces driving our industry and impacting our operations, whether positive or negative, to maximize our assets, create value for shareholders, and support environmental goals that align with a more positive future.
Business Environment, Market Conditions and Outlook
Our operating and financial results, and those of the oil and gas industry as a whole, are heavily influenced by commodity prices. Oil and gas prices and differentials have, and may continue to, fluctuate significantly as a result of numerous market-related variables, including global geopolitical and economic conditions. As discussed below, our 2020 operating and financial results have been adversely impacted by the deterioration and prolonged weakness in commodity prices resulting from the COVID-19 pandemic and certain actions by foreign oil and gas producers. Commodity prices are currently expected to remain depressed for an extended period of time.
The extent to which our full year 2020 operating and financial results, or that of future periods, will be adversely impacted by the ongoing COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted. We are unable to reasonably predict when, or to what extent, commodity prices and the overall markets and global economy will stabilize, and the pace of any subsequent recovery for the oil and gas industry. Further, to what extent these events do ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors that are not within our control and cannot be predicted, including the duration and extent of the pandemic and speculation as to future actions by Saudi Arabia, Russia and other foreign producers. We have taken steps and continue to work to address the evolving challenges and mitigate mounting repercussions from both the COVID-19 pandemic and the industry downturn on our operations, our financial condition and our people. We continue to plan
18
for a prolonged downturn well into 2021, in spite of recent slight improvements in oil prices. However, given the tremendous volatility and turmoil, there is no certainty that the measures we take will ultimately be sufficient.
The COVID-19 Pandemic and Industry Downturn
In December 2019, a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, was reported to have surfaced in China. In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic. The COVID-19 pandemic has caused significant disruption globally since January 2020 and the U.S. economy continues to experience profound effects. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of the financial and commodity markets. The oil and gas industry has been severely impacted by the steep and prolonged deterioration in the price of oil caused by the significant decrease in demand because of the COVID-19 pandemic and corresponding preventative measures taken around the world to mitigate the spread of the virus, compounded by a supply surge from Saudi Arabia and Russia in the first half of 2020.
In March 2020, OPEC+ failed to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia aggressively increased oil production and exports. The convergence of these events - the unprecedented dual impact of a severe global oil demand decline related to the COVID-19 pandemic coupled with a substantial increase in supply - drove oil prices to historically low levels and created significant volatility, uncertainty, and turmoil in the oil and gas industry. As a result, the price of oil was extremely depressed and even reached historic lows during the second quarter 2020, with the price of Brent crude bottoming to just under $20 per Bbl in mid April 2020. These market conditions prompted producers all over the world to shut-in production and delay new oil and gas projects. OPEC+ eventually announced production cuts in April 2020, and then in June 2020 agreed to extend the cuts through the end of July 2020. In August these production cuts were eased slightly and the current output reduction levels are expected to remain through the end of 2020.
Additionally, the effects of demand destruction with a supply surge globally was amplified during the second quarter 2020 as available storage for crude oil and refined products became increasingly limited and there were concerns that available storage could become completely unavailable in 2020 and beyond, depending on the duration and severity of the ongoing pandemic. With the storage and transportation constraints further adding to the pressure on commodities prices, during the second quarter 2020 refiners started to curtail output and producers all over the world - including in the United States - started to shut-in production. Toward the end of the second quarter 2020, oil prices began to recover as the production cuts reduced the supply overhang and global demand began to increase gradually with containment of the COVID-19 outbreak in areas around the globe. The storage concerns were partially relieved as a result. However, this recovery appears fragile and has flattened, with oil price recovery stalling and oil demand remaining below pre-COVID-19 pandemic levels. Demand, and pricing, may again decline due to the ongoing COVID-19 pandemic, particularly if there is a resurgence of the outbreak as some are suggesting is possible, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time.
As we focus on managing our business and operations in response to this health and economic crisis, the safety and well-being of our employees and the communities in which we operate has been, and is, our top priority. For the protection of our employees and to help contain the spread of COVID-19, we modified our business practices, including temporary closing of offices not required to maintain critical operations and instead allowing a large portion of our workforce to work from home, and we have implemented recommended practices with respect to social distancing, quarantines, travel bans and other restrictions. Although we managed the transition to remote work arrangements and subsequent office reopening without a loss in business continuity, we incurred additional costs and experienced some inefficiencies; importantly, none of which had an impact on our financial reporting systems, internal control over financial reporting or disclosure controls and procedures. We have not had layoffs or furloughs year-to-date, in part due to the “essential” nature of our business. As discussed above, the situation remains volatile and, if there is a resurgence of the COVID-19 outbreak in our areas of operation, we may be forced to again temporarily close our offices and transition to work from home; although we currently expect our operations would continue as normal and without significant additional impact due to the essential nature of our business. We remain
19
committed to being a good corporate citizen by focusing on the well-being of our employees and communities, including maintaining our strong safety and environmental standards and investing in community impact initiatives.
As a result of the industry downturn, commodity price outlook, and increasing uncertainty, on April 1, 2020, we provided updated guidance for the 2020 fiscal year, reflecting a heightened focus on preserving cash and reducing costs, including through reducing planned 2020 capital expenditures and non-employee general and administrative expenses and improving operational efficiencies. We also temporarily suspended our quarterly cash dividend, starting with the second quarter of 2020, and year-to-date we have not repurchased any common stock under our authorized share repurchase program. We enhanced our hedge positions for 2020 and we still have essentially all of our expected oil production hedged in the remainder of 2020 at nearly $60 per barrel. We have hedged the substantial majority of our expected first half of 2021 oil production and have hedged just less than half of expected production for the second half of 2021. Additionally in October 2020, we hedged 12,500 MMBtu/d of our 2021 Rockies gas production at nearly $3.00 per MMBtu. Low oil and gas prices are expected to continue for some period as reflected by the current futures forward curves for Brent crude and Henry Hub gas, and we have secured these hedge positions to protect against the anticipated prolonged weakness in commodity prices. However, ongoing or worsening economic impacts to our industry could adversely impact our financial results through 2021 or beyond.
We experienced a decrease in production for the second and third quarters of 2020, largely due to natural declines as a result of temporarily discontinuing our drilling activity in April and engaging proactive maintenance and well management activities. We restarted our drilling activity in mid-October 2020, which we currently expect to continue through 2021 if our financial position and market conditions continue to support it. As a result, capital spending for the full year 2020 is now expected to be approximately $72 million, excluding capitalized overhead. During the second quarter of 2020, we obtained additional storage capacity to support our planned production for the remainder of the year and into 2021. As market conditions improved, we released a portion of the capacity. We currently believe our storage capacity will be sufficient to support our current planned production and we do not anticipate shutting in production in the near future unless economics dictate. However, the risk remains that storage for oil may be unavailable and our existing capacity may be insufficient to support planned production rates in the event of demand for our oil deteriorating again or a supply surge or both. If we are unable to obtain additional storage capacity if needed, we could be forced to shut-in some or all of our production or delay or temporarily discontinue our drilling plans. This could have a material, adverse effect on our financial condition, liquidity and results of operations. Whether and when we will have to reduce or shut-in production, and the extent and duration to which we may have to do so, cannot be reasonably predicted at this time. The significance of the impact of any production disruptions, including the extent of the adverse impact on our short- and long-term financial condition, liquidity and results of operations, will be dictated by the extent and duration of such disruption, which is unknowable and will, in turn, depend on how long storage remains filled and unavailable to us, which is also unknowable. For a discussion of certain potential risks, costs and other considerations related to shutting-in production, please see Part II, Item 1A. Risk Factors in this report - “The marketability of our production is dependent upon transportation and storage facilities and other facilities, most of which we do not control, and the availability of such transportation and storage capabilities, which have been severely limited by recent market conditions related to the COVID-19 pandemic and the current oversupply of oil and natural gas. If additional facilities do not become available, or, even if such facilities are available, but we are unable to access such facilities on commercially reasonable terms, our operations will likely be interrupted, our production could be curtailed, and our revenues reduced, among other consequences.”
Commodity Pricing and Differentials
Our revenue, costs, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, 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 riskprices we pay for our 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 ofpurchases, which are relatively low-costaffected by a variety of factors, including those discussed in contrast to modern unconventional resource plays. Our decades-old proven completion techniquesPart II, Item 1A. “Risk Factors” in these reservoirs include steamflood and low-volume fracture stimulation.

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,this Quarterly Report, as well as in Part I, Item 1A. “Risk Factors” in our Annual Report. Average oil prices were higher for 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 techniquesthree months ended September 30, 2020 compared to increase recoveries.

Using SEC Pricing as of December 31, 2017, we had estimated total proved reserves of 141,384 MBoe. For the three months ended June 30, 2018,2020 but lower than the three months ended September 30, 2019. Brent crude oil contract prices ranged from $45.86 per Bbl to $39.61 per Bbl during the third quarter of 2020. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. During the second quarter of 2020, we had average productionexperienced an adverse
20
widening in the price differential between Brent and California crude due to the lack of which approximately 80% was oil.local demand and storage capacity. This differential widening improved in the third quarter 2020 as the market storage concerns began to soften. As described above, if economic and health situations from the COVID-19 pandemic cause demand to worsen, and/or if OPEC+ producers take actions that again create a supply surge, and if necessary storage availability is not sufficient, oil prices may again go materially lower and Brent and/or California pricing could potentially even become negative as WTI oil prices did on April 20, 2020. In California, ourthe price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, which was as high as $12.69 per MMBtu and as low as $1.37 per MMBtu during the third quarter of 2020, while we paid an average productionof $2.84 per MMBtu in this period.
The following table presents the average Brent, WTI, Kern, Delivered, and Henry Hub prices for the three months ended September 30, 2020, June 30, 20182020 and September 30, 2019 and for the nine months ended September 30, 2020 and September 30, 2019:
Three Months EndedNine Months Ended
September 30, 2020June 30, 2020September 30, 2019September 30, 2020September 30, 2019
Oil (Bbl) – Brent$43.34 $33.39 $62.03 $42.53 $64.75 
Oil (Bbl) – WTI$40.87 $28.42 $56.33 $38.55 $57.03 
Natural gas (MMBtu) – Kern, Delivered$2.84 $1.45 $2.50 $2.15 $3.19 
Natural gas (MMBtu) – Henry Hub$2.00 $1.70 $2.38 $1.87 $2.62 
As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 70% of the state’s demand from OPEC+ countries and other waterborne sources, primarily in the Middle East and South America. Without the higher costs and potential environmental impact 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, in appropriate oil price environments, should continue to allow us to realize positive cash margins in California over the cycle. However, California oil prices are determined ultimately by local supply and demand dynamic. Even as Brent pricing fell, and was 18.8 MBoe/d,weak, due to the effects of demand destruction with a supply surge globally, we also experienced a widening in the price differential between Brent and the California benchmark, caused primarily by the lack of local demand and storage capacity. We planned for significant deterioration of these differentials and refinery utilizations, and our plan for this expected worsening situation did not fully materialize, which approximately 100% was oil.enabled us to mitigate the impact. Although market conditions improved and the differential widening softened toward the end of the second quarter 2020, if California pricing weakens, our financial and operating results will be adversely affected. Currently we have storage capacity of 315,000 Bbls through June of 2021 to help mitigate these potential consequences.
Utah oil prices have historically traded at a discount to WTI as the local refineries are designed for Utah's unique oil characteristics and the remoteness of the assets makes access to other markets logistically challenging.

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

Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in Utah and Colorado ("the Rockies"). Additionally, in recent history, the California gas markets have had higher gas prices than the Rockies and the rest of the United States. Consequently, higher gas prices have a negative impact on our operating results. However, we mitigate a portion of this exposure by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. We also strive to minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of such gas purchases. The negative impact of higher gas prices on our California operating expenses is partially offset by higher gas sales for the gas we produce in the Rockies.

21

Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by three of our cogeneration facilities under long-term contracts with terms ending in July 1, 2021 through December 1, 2026. The most significant input and cost of the cogeneration facilities is natural gas. We generally receive significantly more revenue from these cogeneration facilities in the summer months, June through September, due to negotiated capacity payments we receive.

EH&S and Regulatory Matters

Chapter 11 BankruptcyLike other companies in the oil and Our Emergence

gas industry, our operations are subject to complex and stringent federal, state, and local laws and regulations relating to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing, and sale of our products. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and abandonment requirements for the oil and natural gas industry could have a significant impact on operations. Federal, state, and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
In 2013,California, the Linn Entities acquiredjurisdiction, duties and enforcement authority of various state agencies have significantly increased with respect to oil and natural gas activities in recent years, and these state agencies, as well as certain cities and counties, have significantly revised their regulations, regulatory interpretations and data collection and reporting requirements. For example:
•In April 2019 new idle well regulations went into effect, which include a comprehensive well testing regime to prevent leaks, a compliance schedule for testing or plugging and abandoning idle wells, the collection of data necessary to prioritize testing and sealing idle wells, requirements for a long-term idle well management plan, an engineering analysis for each well idled 15 years or longer, and requirements for active observation wells. In California, an idle well is one that has not been used for two years or more and has not yet been permanently sealed pursuant to regulations from California Geologic Energy Management Division ("CalGEM"), California's primary regulator of the oil and natural gas industry on private and state lands. We have submitted the required plans to meet our obligations.
•CalGEM’s predecessor companyalso finalized new Underground Injection Control (“UIC”) regulations, effective April 2019, which affect two types of wells: (i) those that inject water or steam for enhanced oil recovery and (ii) those that return the briny groundwater that comes up from oil formations during production. These regulations include stronger testing requirements designed to identify potential leaks, increased data requirements to ensure proposed projects are fully evaluated, continuous well pressure monitoring, requirements to automatically cease injection when there is a risk to safety or the environment, and requirements to disclose chemical additives for injection wells close to water supply wells. Our California development and production activities are subject to these UIC regulations.
•Legislation passed in exchange2019 took effect January 1, 2020, including AB 1057, which requires state agencies to review emissions from idle and abandoned wells, and valuate plugging and abandonment and restoration costs and associated bonding requirements. This legislation also expanded CalGEM’s duties to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs.
•Additionally, in November 2019, California's Department of Conservation issued a press release announcing three actions by CalGEM: (1) a moratorium on approval of new high–pressure cyclic steam wells pending a study of the practice to address surface expressions experienced by certain operators; (2) review and updating of regulations regarding public health and safety near oil and natural gas operations pursuant to additional duties assigned to CalGEM by the Legislature in 2019; and (3) a performance audit
22
of CalGEM's permitting processes for LinnCo shareswell stimulation treatment (“WST”) permits and project approval letters (“PALs”) for underground injection by the California Department of Finance and an independent review and approval of the technical content of pending WST and PAL applications by Lawrence Livermore National Laboratory. In January 2020, CalGEM issued a formal notice to operators, including us, that they had issued restrictions imposing a moratorium to prohibit new underground oil-extraction wells from using high-pressure cyclic steaming process. Only our undeveloped thermal diatomite assets are currently impacted by the moratorium. Our 2020 results have not been, and are not expected to be, significantly impacted by the moratorium because our 2020 development and production plans did not require new high-pressure cyclic steam injection and the assumptionmoratorium does not impact existing production or previously approved permits.
•On September 23, 2020, California’s Governor Gavin Newsom issued Executive Order N-79-20 related to vehicular transportation emissions and fossil fuel production in California. The order establishes a number of debt with an aggregate valuenew policy goals for the State of $4.6 billion. A severe industry downturn, coupled with high leverageCalifornia and significant fixed charges, leddirects the Linn Entitiesstate legislature and consequently, our predecessor companyagencies to initiatedevelop policies or conduct rulemakings in furtherance of these goals. Specifically, the Chapter 11 Proceedingsorder addresses (1) working to end the issuance of new hydraulic fracturing permits by 2024, (2) development of a plan to transition upstream and downstream oil facilities by July 2021, (3) the need for strict enforcement of bonding requirements and other oil and gas regulations by CalGEM, and (4) development of new, draft public health and safety rules by December 31, 2020. The potential impact on May 11, 2016.

On February 28, 2017, Berry LLC emerged from bankruptcy as a stand-alone company and wholly-owned subsidiarywill depend on the nature of Berry Corp. with new management, a new board of directors and new ownership. Through the Chapter 11 Proceedings, the Company significantly improved its financial position from that of Berry LLC while it was ownedany final rules, regulations, policies, or legislation adopted by the Linn Entities. These improvements included:state agencies or passed by the state legislature. As such, impacts to Berry cannot be predicted at this time.

•Legislation passed in 2020 will take effect January 1, 2021, although emergency measures take effect immediately upon signature by the Governor. Legislation signed into law in 2020 includes expanded oil spill penalties, new reporting requirements for excavations and subsurface installations, new protections for workers and disclosure requirements related to COVID-19.
• the elimination of approximately $1.3 billion of debtViolations and more than $76 million of annualized interest expense;
• the termination of, or renegotiation of more favorable terms for, several firm transportation and oil sales contracts;
• the anticipated reduction in recurring general and administrative costs as a stand-alone company by following a lean operating model.

On the Effective Date, Berry LLC consummated the following reorganization transactions in accordanceliabilities with the Plan:

• Linn Acquisition Company, LLC transferred 100%respect to any of the outstanding membership interestsapplicable laws and regulations, including those related to any environmental incident, could result in Berry LLCsignificant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, an inability to Berry Corp. pursuantreceive permits, operational interruptions or shutdowns and other liabilities. Additionally, the costs of remedying any environmental incident may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects. For additional information, please see Part I, Item 1 “Regulation of Health, Safety and Environmental Matters”, as well as Part I, Item 1.A. “Risk Factors” in our Annual Report.
For additional information, please see Part I, Item 1 “Regulation of Health, Safety and Environmental Matters”, as well as Part I, Item 1.A. “Risk Factors” in our Annual Report.
Seasonality
Seasonal weather conditions can impact our drilling and production activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to the Assignment Agreement. Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.

• The holders of claims under the Pre-Emergence Credit Facility, received (i) their pro rata share of a cash paydownshortages and (ii) pro rata participationincrease costs or delay operations. For example, our operations have been and in the Emergence Credit Facility. As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceledfuture may be impacted by ice and the agreements governing these obligations were terminated.

• Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A., as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments.

• The holders of Berry LLC’s Unsecured Notes received a right to their pro rata share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors that irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool and (ii) specified rights to participate the Berry Rights Offerings. As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.

• The holders of the Unsecured Claims received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii)snow in the event that such holder irrevocably elected to receive a cash recovery, cash distributions fromwinter and by electrical storms and high temperatures in the Cash Distribution Pool. The obligations arising from the Unsecured Claims were extinguished.spring and summer, as well as by wild-fires and rain.

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

How We Plan and Evaluate Operations

We use “Levered Free Cash Flow” in planning our capital allocation to sustain production levels and fund internal growth opportunities, as well as determine hedging needs. Levered Free Cash Flow is a non-GAAP financial measure that we define as Adjusted EBITDA less capital expenditures, interest expense, and dividends. Adjusted EBITDA is also a non-GAAP financial measure that is discussed and defined below.
Our management team uses
23
We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) operating expenses; (c) environmental, health & safety (“EH&S”) results; (d) taxes, other than income taxes; (e) general and administrative expenses; (f) production; and (g) levered free cash flow.

(e) production.
Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business. We define Adjusted EBITDA is a non-GAAP financial measure that we defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization and accretion; exploration expense;(“DD&A”); derivative gains or losses net of cash received or paid

for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization costs.

items.
Operating expensesExpenses

Overall, operating expense is used by management as a measure of the efficiency with which operations are performing. We define operating expenses as lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity, transportation and marketing activities.activities, as well as the effect of derivative settlements (received or paid) for gas purchases. Marketing revenues represent sales of natural gas purchased from and sold to third parties. Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Taxes other than income taxes are excluded from operating expenses. The electricity, transportation and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economics of development projects and the efficiency of our hydrocarbon recovery. Overall, operating expense is used by management as a measureAdditionally, we strive to minimize the variability of our fuel gas costs for our steam operations with gas hedges.
Environmental, Health & Safety
Like other companies in the efficiency with whichoil and gas industry, our operations are performing.subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Current and future laws and regulations, as well as legislative and regulatory changes and other government activities, can materially impact our exploration, development, production and abandonment plans, including by restricting the production rate of oil, natural gas and NGLs below the rate that would otherwise be possible. Additionally, the regulatory burden on the industry increases the cost of doing business and consequently effects capital expenditures and earnings.

Environmental, health & safety

We are committedAs part of our commitment to good corporate citizenshipcreating long-term stockholder value, we strive to conduct our operations in our communities, operating safelyan ethical, safe and protectingresponsible manner, to protect the environment and to take care of our employees.people and the communities in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the communities in which we operate and our other stakeholders in order to realize the full potential of our resources in a timely fashion that safeguards people and the environment and complies with existing laws and regulations. We monitor our EH&S performance through various measures, holdingand incentivize our employees and contractors to perform at high standards. Meeting corporate EH&S metrics is a part ofstandards, including through our annual short-term incentive programs for all employees.

Taxes, other than income taxes

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

program.
General and administrative expenses

Administrative Expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities.activities and less than 10% of such costs are capitalized, which is significantly less than industry norms. Such expenses are a key component of the appropriate level of support our corporate and professional team provides to the development of our assets and our day-to-day operations.

24
Production

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

Levered free cash flow

Levered free cash flow reflects our financial flexibility; and we use it to plan our internal growth capital expenditures. We define levered free cash flow as Adjusted EBITDA less capital expenditures, interest expense and dividends. Levered free cash flow is our primary metric used in planning capital allocation for maintenance and internal growth opportunities as well as hedging needs and serves as a measure for assessing our financial performance and measuring our ability to generate excess cash from our operations after servicing indebtedness.

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 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) attributable to common stockholders 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 and reorganization costs 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; exploration expense; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring and reorganization costs. 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.
























The following tables present reconciliations of the non-GAAP financial measure Adjusted EBITDA and Levered Free Cash Flow to the GAAP financial measures of net income (loss) and net cash provided or used by operating activities for each of the periods indicated.
 Berry Corp. (Successor)Berry LLC (Predecessor)
 Three Months EndedThree Months EndedThree Months Ended Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018March 31, 2018June 30, 2017 June 30, 2018June 30, 2017February 28, 2017
 (in thousands)
Adjusted EBITDA reconciliation to net income (loss):       
Net income (loss)$(28,061)$6,410
$12,120
 $(21,651)$23,497
$(502,964)
Add (Subtract):       
Depreciation, depletion, amortization and accretion21,859
18,429
20,549
 40,288
27,571
28,149
Interest expense9,155
7,796
4,885
 16,951
6,600
8,245
Income tax expense (benefit)(5,476)939
7,961
 (4,537)15,435
230
Derivative (gain) loss78,143
34,644
(23,962) 112,787
(48,085)(12,886)
Net cash received (paid) for scheduled derivative settlements(28,261)(17,849)4,725
 (46,110)5,856
534
(Gain) loss on sale of assets and other123
—
5
 123
5
(183)
Stock compensation expense1,278
1,042
—
 2,320
—
—
Non-recurring restructuring and other costs1,714
2,047
16,846
 3,761
24,442
—
Reorganization items, net(456)(8,955)(713) (9,411)593
507,720
Adjusted EBITDA50,018
44,503
42,416
 94,521
55,914
28,845
Net cash (received) paid for scheduled derivative settlements28,261
17,849
(4,725) 46,110
(5,856)(534)
Adjusted EBITDA unhedged$78,279
$62,352
$37,691
 $140,631
$50,058
$28,311









 Berry Corp. (Successor)Berry LLC (Predecessor)
 Three Months EndedThree Months EndedThree Months Ended Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018March 31, 2018June 30, 2017 June 30, 2018June 30, 2017February 28, 2017
 (in thousands)
Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided (used) by operating activities:       
Net cash provided (used) by operating activities$(77,394)$27,846
$20,703
 $(49,548)$44,937
$22,431
Add (Subtract):       
Cash interest payments644
2,654
4,860
 3,298
5,261
8,057
Cash income tax payments—
—
1,168
 —
1,168
—
Cash reorganization item (receipts) payments1,047
305
(1,384) 1,352
(792)11,838
Non-recurring restructuring and other costs1,714
2,047
16,846
 3,761
24,442
—
Derivative early termination payment126,949
—
—
 126,949
—
—
Other changes in operating assets and liabilities(2,942)11,651
223
 8,709
(19,102)(13,323)
Other, net—
—
—
 —
—
(158)
Adjusted EBITDA50,018
44,503
42,416
 94,521
55,914
28,845
Subtract:       
Capital expenditures(39,196)(15,732)(24,697) (54,928)(34,050)(5,407)
Interest expense(9,155)(7,796)(4,885) (16,951)(6,600)(8,245)
Dividends(5,650)(5,650)(5,404) (11,301)(7,196)—
Levered Free Cash Flow(3,983)15,325
7,430
 11,341
8,068
15,193
Net cash (received) paid for scheduled derivative settlements28,261
17,849
(4,725) 46,110
(5,856)(534)
Levered Free Cash Flow unhedged$24,278
$33,174
$2,705
 $57,451
$2,212
$14,659














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) attributable to common stockholders.
 Berry Corp. (Successor)Berry LLC (Predecessor)
 Three Months EndedThree Months EndedThree Months EndedSix Months EndedFour Months EndedTwo Months Ended
 June 30, 2018March 31, 2018June 30, 2017June 30, 2018June 30, 2017February 28, 2017
Adjusted Net Income (Loss) reconciliation to Net income (loss) attributable to common stockholders(in thousands)
Net income (loss) attributable to common stockholders$(33,711)$760
$6,716
$(32,952)$16,301
$(502,964)
       
Add (Subtract):      
Losses (gains) on oil and natural gas derivatives78,143
34,644
(23,962)112,787
(48,085)(12,886)
Net cash received (paid) for scheduled derivative settlements(28,261)(17,849)4,725
(46,110)5,856
534
Losses (gains) on sale of assets and other, net123
—
5
123
5
(183)
Non-recurring restructuring and other costs1,714
2,047
16,846
3,761
24,442
—
Reorganization items, net(456)(8,955)(713)(9,411)593
507,720
 51,263
9,887
(3,099)61,150
(17,189)495,185
Income tax (expense) benefit of adjustments at effective tax rate(8,370)(1,263)1,229
(10,594)6,815
 n/a
Adjusted Net Income (Loss)$9,182
$9,384
$4,846
$17,604
$5,927
$(7,779)

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 EndedThree Months EndedThree Months Ended Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018March 31, 2018June 30, 2017 June 30, 2018June 30, 2017February 28, 2017
 (in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:       
General and administrative expenses$12,482
$11,985
$22,257
 $24,466
$31,800
$7,964
Subtract:       
Non-recurring restructuring and other costs(1,714)(2,047)(16,846) (3,761)(24,442)—
Non-cash stock compensation expense(1,260)(1,019)—
 (2,279)—
—
Adjusted General and Administrative Expenses$9,508
$8,919
$5,411
 $18,426
$7,358
$7,964
        

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

Basis of Presentation and Fresh-Start Accounting

Upon Berry LLC’s emergence from bankruptcy, we adopted fresh-start accounting, which, with the recapitalization upon emergence from bankruptcy, resulted in Berry Corp. becoming the financial reporting entity in our corporate group.

Unless otherwise noted or suggested by context, all financial information and data and accompanying financial statements and corresponding notes, as contained in this Quarterly Report on Form 10-Q, on or prior to the Effective Date, reflect the actual historical results of operations and financial condition of our predecessor company for the periods presented and do not give effect to the Plan or any of the transactions contemplated thereby or the adoption of fresh-start accounting. Following the Effective Date, they reflect the actual historical results of operations and financial condition of Berry Corp. on a consolidated basis and give effect to the Plan and any of the transactions contemplated thereby and the adoption of fresh-start accounting. Thus, the financial information presented herein on or prior to the Effective Date is not comparable to Berry Corp.’s performance or financial condition after the Effective Date. As a result, “black-line” financial statements are presented to distinguish between Berry LLC as the predecessor and Berry Corp. as the successor.

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

The main actions we took affecting comparability between periods presented include the reorganization of Berry LLC through bankruptcy, entry into the RBL Facility, issuance of the 2026 Notes, dividends on and conversion of Series A Preferred Stock and completion of the IPO. These actions are described above under "-Chapter 11 Bankruptcy and our Emergence" and below in "Liquidity and Capital Resources."

Capital Expenditures and Capital Budget

For the three and sixnine months ended JuneSeptember 30, 2018,2020, our capital expenditures were approximately $39$4 million and $54$57 million, respectively, on an accrual basis excluding acquisitions.

Following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities, we increased our pace of development and have continued to do so in 2018. Our 2018 anticipated capital expenditure budgetcapitalized overhead of approximately $140$1.5 million and $4.5 million, respectively. These amounts also excluded capitalized interest, acquisitions and asset retirement spending. Approximately 90% of total capital for the nine months ended September 30, 2020 was directed to $160 million represents an increaseCalifornia oil operations.
Toward the end of approximately 107% overthe first quarter we reduced our 2017planned 2020 capital expenditures by approximately 50% from our original 2020 guidance in response to the sudden and significant oil and gas price deterioration caused by the COVID-19 pandemic, coupled with OPEC+ actions, which created significant volatility, uncertainty, and turmoil in the oil and gas industry. Since that time, the 2020 capital expenditures have been focused on continuing our permitting and proactive maintenance activities to support ongoing activity and safe operations. We proactively initiated an intense permitting program during the first quarter 2020 to ensure adequate inventory once we restarted our drilling program. With the slight strengthening of oil prices in the third quarter 2020, capital spending for the full year is now expected to be approximately $72 million, which excludes approximately $7 million of capitalized overhead. This includes restarting our drilling program in mid-October 2020, as well as increasing workover and recompletion opportunities during the fourth quarter 2020. The 2020 capital expenditures also includes approximately $25 million for facilities and cogen projects, including long-term maintenance, as well as approximately $4 million for drilling delineation wells which added value by increasing our reserves and drilling inventory for these projects.
We currently expect 2020 production to be flat with the successor and predecessor periods,prior year. We also anticipate oil production will be approximately 88% of approximately $73 million.total production in 2020, compared to 87% in 2019. Based on our current commodity prices and a drilling success rate comparablecapital plan we expect to our historical performance, we believe we will be able to fund our 2018remaining 2020 capital program exclusivelydevelopment programs with our levered free cash flow. We expect to:
• employ:
• three drilling rigsflow from operations. Even in California for the remainder of 2018;
• one additional drilling rig assignedthis low price environment we plan to drilling opportunities in Utahlive within Levered Free Cash Flow over 2020 and 2021 in the second half of 2018;
• drill approximately 180 to 190 gross development wells in 2018, of which we expect at least
175 will be in California.
The table below sets forth the expected allocation of our 2018 capital expenditure budget by area as compared to the allocation of our 2017 capital expenditures.
Capital Expenditure by Area
2018 Budget2017 Actual
(in millions)
California$122-136

$71
Uinta12-16
1
Piceance1-2
1
East Texas—
—
Corporate5-6
—
Total$140-160

$73
aggregate, and beyond.
The amount and timing of these capital expenditures isare within our control and subject to our management’s discretion.discretion, and may be adjusted during the year depending on commodity prices, storage constraints, supply/demand considerations and other factors. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, the availability of necessary equipment, infrastructure and capital, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or eliminationowners, as well as general market conditions. Additionally and not included in the capital expenditures noted above, for the full year 2020, we plan to spend approximately $16-$20 million on plugging and abandonment activities, including satisfying our annual obligations under the California Idle Well Management Program. This includes the $14 million spent in the first three quarters of our development drilling program could result in a reduction2020.
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Chevron North Midway-Sunset Acquisition
In April 2018,May 2020, we completedacquired approximately 740 net acres in the Chevron North Midway-Sunset Acquisition.Midway Sunset Field for approximately $5 million. We assumed apaid $2 million at closing and the remaining $3 million was paid following our first production from this property, in the fourth quarter 2020. This property is adjacent to, and extends, our existing producing area and we have identified numerous future drilling commitment for the 214 acreslocations. We believe additional opportunities exist in other productive reservoirs of approximately $34.5 million to drill 115this property. We also acquired all existing idle wells on this property, some of which none have been drilled,we plan to return to production in the near future as price and strategy dictate. We will plug and abandon the remaining idle wells pursuant to the California Idle Well Management Program. We recorded a $6 million liability for asset retirement obligations of the existing wells on or before April 1, 2020, which has been extended to April 1, 2022, and would assume an additional 40 well drilling commitment if we exercise our option on the 490 acres. We paid no other consideration for the acquisition. Our drilling commitment will be tolled for a month for each consecutive 30-day period for which the posted pricethis property.
26
our business strategy to investigate areas beyond our known productive areas.

Commodity Derivatives
Recently, we have utilized swaps, puts and calls to hedge a portion of our forecasted production and reduce exposure to fluctuations in oil and natural gas prices. Swap contracts are designed to provide a fixed price. For fixed-price swaps, we make settlement payments for prices above the indicated weighted-average price per barrel of Brent and receive settlement payments for prices below the indicated weighted average price per barrel of Brent. For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated weighted average price per barrel and receive settlement

payments if the difference between Brent and WTI is below the indicated weighted average price per barrel. We earn a premium on our sold oil calls at the time of sale. We make net settlement payments for prices above the indicated weighted-average price per barrel of Brent. If the calls expire unexercised, no payments are received. For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel of Brent. Currently, our hedging program mainly consists of swaps and put options.
Our open derivative positions as of June 30, 2018 were as follows:
Contents
 201820192020
Sold Oil Calls (ICE Brent):   
  Hedged volume (MBbls)186
—
—
  Weighted average price ($/Bbl)$81.67
$—
$—
Purchased put options (ICE Brent) :   
  Hedged volume (MBbls)—
2,835
455
  Weighted average price ($/Bbl)$—
$65.00
$65.00
Fixed Price Swaps (ICE Brent)   
  Hedged volume (MBbls)1,932
900
—
  Weighted average price ($/Bbl)$75.13
$75.66
$—
Oil basis differential positions:   
ICE Brent - NYMEX WTI basis swaps   
  Hedged volume (MBbls)184
182.5
—
  Weighted average price ($/Bbl)$1.29
$1.29
$—
Summary By Area
The following table summarizes the historical resultsshows a summary by area of our hedging activities.
 Berry Corp. (Successor)Berry LLC (Predecessor)
 Three Months EndedThree Months EndedThree Months EndedSix Months EndedFour Months EndedTwo Months Ended
 June 30, 2018March 31, 2018June 30, 2017June 30, 2018June 30, 2017February 28, 2017
Crude Oil (per Bbl):      
Realized price, before the effects of derivative settlements$67.93
$62.14
$44.27
$65.06
$44.34
$46.94
Effects of derivative settlements$(14.71)$(9.40)$2.70
$(12.08)$2.50
$0.46
       
We expect our operations to generate substantial cash flows at current commodity prices. We have protected a portion of our anticipated cash flows through 2020 as part of our crude oil hedging program. Our low-decline production base, coupled with our stableselected historical financial information and operating cost environment, affords an ability to hedge a material amount of our future expected production.
In May 2018, we elected to terminate outstanding commodity derivative contracts for all WTI oil swaps and certain WTI/Brent basis swaps for July 2018 through December 2019 and all WTI oil sold call options for July 2018 through June 2020. Termination costs totaled approximately $127 million and were calculated in accordance with a bilateral agreement on the cost of elective termination included in these derivative contracts; the present value of the contracts using the forward price curve as of the date termination was elected. No penalties were charged as a result of the elective termination. Concurrently, Berry Corp. entered into commodity derivative contracts consisting of Brent oil swaps for July 2018 through March 2019 and Brent oil purchased put options for January 2019 through March 2020. These Brent oil swaps hedge 1.8 MMBbls in 2018 and 0.9 MMBbls in 2019 at a weighted average price of $75.66. These Brent oil purchased put options provide a weighted average price floor of $65.00 for 2.8 MMBbls in 2019 and 0.5 MMBbls in 2020. We effected these transactions to move from a WTI-based position to a Brent-based position as well as bring our hedged pricing more in line with current market pricing.


Income Taxes
Prior to the Effective Date, Berry LLC was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of Berry LLC. Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC in a taxable asset acquisition as part of the restructuring. Consequently, we are now taxed as a corporation and have no net operating loss carryforwardsdata for the periods prior to February 28, 2017.indicated.
California
(San Joaquin and Ventura basins)
Three Months Ended
September 30, 2020June 30, 2020September 30, 2019
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales$81,592 $62,943 $124,540 
Operating income (1)
$36,296 $32,469 $66,449 
Depreciation, depletion, and amortization (DD&A)$34,779 $36,518 $24,360 
Average daily production (MBoe/d)22.2 23.4 23.0 
Production (oil % of total)100 %100 %100 %
Realized sales prices:
Oil (per Bbl)$40.02 $29.53 $59.00 
NGLs (per Bbl)$— $— $— 
Gas (per Mcf)$— $— $— 
Capital expenditures(2)
$4,467 $15,916 $59,076 
On December 22, 2017, the U.S. the Tax Cuts
Utah
(Uinta basin)		Colorado
(Piceance basin)
Three Months EndedThree Months Ended
September 30, 2020June 30, 2020September 30, 2019September 30, 2020June 30, 2020September 30, 2019
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales$9,311 $6,439 $14,946 $1,336 $1,132 $1,758 
Operating income (loss)(1)
$1,093 $(584)$1,376 $(235)$6 $(123)
Depreciation, depletion, and amortization (DD&A)$915 $905 $3,039 $165 $43 $264 
Average daily production (MBoe/d)4.1 4.4 5.1 1.3 1.3 1.5 
Production (oil % of total)47 %49 %52 %2 %2 %2 %
Realized sales prices:
Oil (per Bbl)$38.40 $23.11 $48.74 $33.60 $20.67 $56.18 
NGLs (per Bbl)$13.25 $5.82 $12.10 $— $— $— 
Gas (per Mcf)$2.05 $1.68 $2.21 $1.80 $1.53 $1.99 
Capital expenditures(2)
$103 $82 $1,851 $46 $145 $213 
__________
(1)    Operating income (loss) includes oil, natural gas and Jobs Act (the “Act”) which made significant changes to the Internal Revenue CodeNGL sales, and scheduled oil derivative settlements, offset by operating expenses (as defined elsewhere), general and administrative expenses, DD&A, impairment of 1986, including lowering the maximum federal corporate rate from 35 percent to 21 percent and imposing limitations on the use of net operating losses arising in taxable years ending after December 31, 2017.  This was the key contributor to the decrease in our effective rate from 40% in the 2017 Successor periods to 16% and 17% in the three and six months ended June 30, 2018, respectively.  We anticipate earnings for fiscal year 2018, in part due to the termination and resetting of our hedge positions in May 2018. These earnings consequently allow for the release of our valuation allowance, resulting in an effective tax rate less than the maximum federal and applicable state tax rate for the six months ended June 30, 2018.There were no current income taxes during the six months ended June 30, 2018

Our accounting for the U.S. Tax Reform Act is incomplete. As noted at year-end, however, we were able to reasonably estimate certain effects and, therefore, recorded provisional adjustments to income tax expense for the revaluation of deferred tax assets and liabilities from 35 percent to 21 percent associated with the reduction in the U.S. corporate income tax rate, and for a valuation allowance on certain deferred tax assets impacted by the Act. We have not revised any of the 2017 provisional estimates. Any subsequent adjustments to these amounts will be recorded to income tax expense in the quarter the analysis is complete.
Business Environment and Market Conditions
The oil and gas industry is heavily influenced by commodity prices. Since the latter half of 2014, commodity prices have declined and remained at relatively low levels through the middle of 2017 but have generally risen since then. For example, the Brent crude oil futures contract prices declined from a high of over $100.16 per Bbl on June 24, 2014 to a low of $40.67 per Bbl on January 20, 2016. The Henry Hub spot price for natural gas has also declined since 2014, though reduced gas prices are a net benefit to our results of operations. While oil prices remain lower than the 2014 averages, they have improved since early 2016. Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production.
The following table presents the average Intercontinental Exchange Brent oil ("Brent"), New York Mercantile Exchange ("NYMEX") WTI oil and NYMEX Henry Hub natural gas prices for the three months ended June 30, 2018, March 31, 2018 and June 30, 2017, the six months ended June 30, 2018, the four months ended June 30, 2017 and the two months ended February 28, 2017:
 Berry Corp. (Successor)Berry LLC (Predecessor)
 Three Months EndedThree Months EndedThree Months EndedSix Months EndedFour Months EndedTwo Months Ended
 June 30, 2018March 31, 2018June 30, 2017June 30, 2018June 30, 2017February 28, 2017
ICE (Brent) oil ($/Bbl)$74.87
$67.16
$50.90
$71.01
$51.31
$55.72
NYMEX (WTI) oil ($/Bbl)$67.76
$62.87
$48.28
$65.32
$48.63
$53.04
NYMEX Henry Hub natural gas ($MMBtu)$2.80
$3.00
$3.18
$2.90
$3.05
$3.66
Oil prices and differentials will continue to be affected by a variety of factors, including worldwide and regional economic conditions, transportation costs, imports, political conditions in producing regions, exploration levels, inventory levels, the actions of the Organization of Petroleum Exporting Countries ("OPEC") and other state-controlled oil companies and significant producers, local pricing, gathering facility and transportation dynamics, exploration, development, production and transportation costs, the effects of conservation, weather, geophysical and technology, refining and processing disruptions, exchange rates, taxes and

regulations and other matters affecting the supply and demand dynamics for oil, technological advances, regional market conditions, transportation capacity and costs in producing areas and the effect of changes in these variables on market perceptions.
California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign sources. There is a closer correlation of prices in California to Brent pricing than to WTI. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low-cost transportation of crude, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California.
Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.
Natural gas prices and differentials are strongly affected by local market fundamentals, as well as availability of transportation capacity from producing areas. Higher natural gas prices have a net negative effect on our operating results. We use substantially more natural gas for our steamfloods and power generation, than we produce and sell. The negative impact of higher prices on our operating costs is, however, partially offset by higher natural gas sales.
Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties, and electricity for off-lease sales. While a portiontaxes, other than income taxes.
(2)    Excludes corporate capital expenditures.
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Seasonality
Seasonal weather conditions and lease stipulations can limit our drilling and producing activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires.
Production Prices and CostsPrices
The following table sets forth information regarding total production, average daily production, average pricestotal production and average costsprices for each of the periods indicated.

Three Months Ended
September 30, 2020June 30, 2020September 30, 2019
Average daily production:(1)
Oil (MBbl/d)24.1 25.6 25.7 
Natural Gas (MMcf/d)18.7 19.2 20.9 
NGL (MBbl/d)0.4 0.3 0.4 
Total (MBoe/d)(2)
27.6 29.1 29.6 
Total Production:
Oil (MBbl)2,218 2,330 2,360 
Natural gas (MMcf)1,719 1,746 1,920 
NGLs (MBbl)33 29 39 
Total (MBoe)(2)
2,537 2,650 2,719 
Weighted-average realized sales prices:
Oil without hedges ($/Bbl)$39.88 $28.98 $57.92 
Effects of scheduled derivative settlements ($/Bbl)$16.28 $25.42 $7.31 
Oil with hedges ($/Bbl)$56.16 $54.40 $65.23 
Natural gas ($/Mcf)$1.95 $1.62 $2.12 
NGL ($/Bbl)$13.25 $5.82 $12.10 
Average Benchmark prices:
Oil (Bbl) – Brent$43.34 $33.39 $62.03 
Oil (Bbl) – WTI$40.87 $28.42 $56.33 
Natural gas (MMBtu) – Kern, Delivered(3)
$2.84 $1.45 $2.50 
Natural gas (MMBtu) – Henry Hub(4)
$2.00 $1.70 $2.38 
 Berry Corp.
(Successor)
 Three Months EndedThree Months EndedThree Months EndedVarianceVariance
 June 30, 2018March 31, 2018June 30, 2017Q2 2018 vs. Q1 2018Q2 2018 vs. Q2 2017
Average daily production:     
Oil (MBbl/d)21.1
21.1
19.2
—
1.9
Natural Gas (MMcf/d)28.0
27.6
73.1
0.4
(45.1)
NGL (MBbl/d)0.7
0.5
2.9
0.2
(2.2)
Total (MBoe/d)(1)26.5
26.2
34.4
0.3
(7.9)
Total Production:     
Oil (MBbl)1,920
1,897
1,752
23
168
Natural gas (MMcf)2,551
2,481
6,656
70
(4,105)
NGLs (MBbl)62
45
267
17
(205)
Total combined production (MBoe)(1)2,408
2,356
3,128
52
(720)
Weighted average realized prices:   —
—
Oil with hedges (Bbl)$53.22
$52.74
$46.97
$0.48
$6.25
Oil without hedges (Bbl)$67.93
$62.14
$44.27
$5.79
$23.66
Natural gas (Mcf)$2.12
$2.64
$2.74
$(0.52)$(0.62)
NGL (Bbl)$24.38
$25.56
$22.72
$(1.18)$1.66
Average Benchmark prices:   $—
$—
Oil (Bbl) – Brent$74.87
$67.16
$50.90
$7.71
$23.97
Oil (Bbl) – WTI$67.76
$62.87
$48.28
$4.89
$19.48
Natural gas (MMBtu) – NYMEX Henry Hub$2.80
$3.00
$3.18
$(0.20)$(0.38)
Average costs per Boe(2):     
Lease operating expenses$17.24
$18.80
$14.62
$(1.56)$2.62
Electricity generation expenses$1.30
$1.94
$1.43
$(0.64)$(0.13)
Electricity sales (2)$(2.48)$(2.31)$(1.83)$(0.17)$(0.65)
Transportation expenses$0.97
$1.26
$3.01
$(0.29)$(2.04)
Transportation sales (2)$(0.09)$—
$—
$(0.09)$(0.09)
Marketing expenses$0.17
$0.25
$0.23
$(0.08)$(0.06)
Marketing revenues (2)$(0.22)$(0.33)$(0.26)$0.11
$0.04
Total operating expenses$16.89
$19.61
$17.20
$(2.72)$(0.31)
General and administrative expenses (3)$5.18
$5.09
$7.11
$0.09
$(1.93)
Depreciation, depletion and amortization$9.08
$7.82
$6.57
$1.26
$2.51
Taxes, other than income taxes$3.62
$3.50
$3.28
$0.12
$0.34
__________
(1)    Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
(2)    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 yearthree months ended December 31, 2017,September 30, 2020, the average prices of ICE (Brent)Brent oil and NYMEX Henry Hub natural gas were $54.82$43.34 per Bbl and $3.11$2.00 per Mcf,MMBtu respectively, resulting in an oil-to-gas ratio of over 17approximately 4 to 1.

(2) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party

gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales, reported in "Other Revenues", relates to water and other liquids that we transport1 on our systems on behalf of third parties.

an energy equivalent basis.
(3)    Includes non-recurring restructuring and other costs and non-cash stock compensation expense,Kern, Delivered Index is the relevant index used for gas purchases in aggregate,California.
(4)    Henry Hub is the relevant index used for gas sales in the Rockies.
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The following table sets forth average daily production by operating area for the periods indicated:
Three Months Ended
September 30, 2020June 30, 2020September 30, 2019
Average daily production (MBoe/d):(1)
California22.2 23.4 23.0 
Utah4.1 4.4 5.1 
Colorado1.3 1.3 1.5 
Total average daily production27.6 29.1 29.6 
 Berry Corp.
(Successor)
 Three Months EndedThree Months EndedThree Months Ended
 June 30, 2018March 31, 2018June 30, 2017
Average daily production (MBoe/d):   
California(1)18.8
18.8
16.3
Hugoton basin(2)—
—
8.6
Uinta basin5.3
5.0
5.9
Piceance basin1.6
1.6
2.5
East Texas0.8
0.8
1.1
 26.5
26.2
34.4
__________
(1)    Production represents volumes sold during the period.
(1)On July 31, 2017, we purchased the remaining approximately 84% working interest of our South Belridge Hill property, located in Kern County, California.
(2)On July 31, 2017, we sold our 78% working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle. Our Hugoton assets represented approximately 24% of our average net daily production for the year ended December 31, 2016.
Average daily production volumes decreased to approximately 26.51.5 MBoe/d, or 23%5%, for the three months ended September 30, 2020, compared to the three months ended June 30, 20182020, largely due to natural declines as a result of temporarily discontinuing our drilling activity in April 2020. Further, we experienced seasonal disruptions and undertook certain operational improvements that caused temporary reductions in our production. Notably, we performed some plugging and abandonment activity that resulted in temporary shut-in of nearby wells. Additionally, we improved steam management which reduced overall costs but temporarily increased water disposal and well maintenance needs, resulting in a slight decrease in production. Our California production of 22.2 MBoe/d for the third quarter 2020 decreased 5% from approximately 34.4 MBoe/dthe second quarter 2020.
Average daily production volumes decreased 7% for the three months ended JuneSeptember 30, 2017. The decrease primarily reflected the decreased natural gas and NGL volumes from the sale of an approximately 78% non-operating, working interest in the Hugoton natural gas field (the "Hugoton Disposition") in July 2017, partially offset by the additional oil volumes from the acquisition of an approximately 84% non-operating, working interest in a South Belridge Hill property, (the "Hill Acquisition") in July 2017. Also contributing to the decrease to a lesser degree was the delay between our increase in capital spending in late 2017 to arrest production declines due to reduced capital spending in 2016 and early 2017, and the effectiveness of the increase which we began to observe in early and mid 2018.
Average daily production volumes increased for the three months ended June 30, 20182020 as compared to the three months ended March 31, 2018September 30, 2019 due to the increasedsignificantly reduced development capital spending in late 2017the second and early 2018.third quarter 2020 compared to the same quarters in 2019. This year-over-year decrease was also impacted by the same reasons noted above.
The following tables settable sets forth information regarding total production, average daily production, total production and average prices and average costs for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods. The information for the six months ended June 30, 2017 are reflected in the tables and narrative discussion that follows in two distinct periods, the four months ended June 30, 2017 and the two months ended February 28, 2017, as a resulteach of our emergence from bankruptcy on February 28, 2017. References in these results of operations to the six months ended June 30, 2017 are used to provide comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for comparing the periods presented.


indicated.
29
 Berry Corp.
(Successor)		Berry LLC (Predecessor)
 Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017February 28, 2017
    
Average Daily Production:   
Oil (MBbl/d)21.1
19.2
19.5
Natural Gas (MMcf/d)27.8
72.8
71.7
NGL (MBbl/d)0.6
3.1
5.2
Total (MBoe/d)(1)26.3
34.4
36.6
Total Production:   
Oil (MBbl)3,818
2,338
1,153
Natural gas (MMcf)5,032
8,877
4,232
NGLs (MBbl)108
379
304
Total combined production (MBoe)(1)4,764
4,196
2,162
Weighted average realized prices:   
Oil with hedges (Bbl)$52.98
$46.84
$47.40
Oil without hedges (Bbl)$65.06
$44.34
$46.94
Natural gas (Mcf)$2.38
$2.67
$3.42
NGL (Bbl)$24.88
$21.64
$18.20
Average benchmark prices:   
Oil (Bbl) – Brent$71.01
$51.31
$55.72
Oil (Bbl) – WTI$65.32
$48.63
$53.04
Natural gas (MMBtu) – NYMEX Henry Hub$2.90
$3.05
$3.66
Average costs per Boe (2):   
Lease operating expenses$18.01
$14.01
$13.06
Electricity generation expenses$1.62
$1.34
$1.48
Electricity sales (2)$(2.40)$(1.57)$(1.69)
Transportation expenses$1.12
$3.11
$2.86
Transportation sales (2)$(0.05)$—
$—
Marketing expenses$0.21
$0.24
$0.30
Marketing revenues (2)$(0.27)$(0.26)$(0.29)
Total operating expenses$18.24
$16.87
$15.72
General and administrative expenses (3)$5.14
$7.58
$3.68
Depreciation, depletion and amortization$8.46
$6.57
$13.02
Taxes, other than income taxes$3.56
$3.18
$2.41
Nine Months Ended
September 30, 2020September 30, 2019
Average daily production:(1)
Oil (MBbl/d)25.7 24.5 
Natural Gas (MMcf/d)18.8 20.4 
NGL (MBbl/d)0.3 0.4 
Total (MBoe/d)(2)
29.1 28.3 
Total Production:
Oil (MBbl)7,033 6,673 
Natural gas (MMcf)5,148 5,565 
NGLs (MBbl)94 116 
Total (MBoe)(2)
7,985 7,717 
Weighted-average realized sales prices:
Oil without hedges ($/Bbl)$39.00 $58.79 
Effects of scheduled derivative settlements ($/Bbl)$16.97 $4.30 
Oil with hedges ($/Bbl)$55.97 $63.09 
Natural gas ($/Mcf)$1.85 $2.67 
NGL ($/Bbl)$10.92 $17.74 
Average Benchmark prices:
Oil (Bbl) – Brent$42.53 $64.75 
Oil (Bbl) – WTI$38.55 $57.03 
Gas (MMBtu) – Kern, Delivered(3)
$2.15 $3.19 
Natural gas (MMBtu) – Henry Hub(4)
$1.87 $2.62 
__________
(1)    Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
(2)    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.

(2) We report electricity, transportation For example, during the nine months ended September 30, 2020, the average prices of Brent oil and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party

gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing expenses mainly relate toHenry Hub natural gas purchased from third parties that moves through our gatheringwere $42.53 per Bbl and processing systems and then is sold$1.87 per MMBtu respectively, resulting in an oil-to-gas ratio of approximately 4 to third parties. Transportation sales, reported in "Other Revenues", relate to water and other liquids that we transport1 on our systems on behalf of third parties.

an energy equivalent basis.
(3)    Includes non-recurring restructuring and other costs and non-cash stock compensation expense,Kern, Delivered Index is the relevant index used for gas purchases in aggregate, of approximately $1.28, $5.83 and none per BoeCalifornia.
(4)    Henry Hub is the relevant index used for gas sales in the Rockies.
The following table sets forth average daily production by operating area for the six months ended June 30, 2018,periods indicated:
Nine Months Ended
September 30, 2020September 30, 2019
Average daily production (MBoe/d):(1)
California23.5 21.6 
Utah4.3 5.2 
Colorado1.3 1.5 
Total average daily production29.1 28.3 
__________
(1)    Production represents volumes sold during the four months ended June 30, 2017 and the two months ended February 28, 2017, respectively.period.
30
 Berry Corp.
(Successor)		Berry LLC (Predecessor)
 Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017February 28, 2017
Average daily production (MBoe/d):   
California (San Joaquin) (1)18.8
16.3
17.0
Hugoton basin(2)—
8.9
10.8
Uinta basin5.1
5.7
5.4
Piceance basin1.6
2.5
2.3
East Texas0.8
1.0
1.1
 26.3
34.4
36.6
Average daily production volumes decreasedincreased 3% for the nine months ended September 30, 2020, compared to approximately 26.3the nine months ended September 30, 2019, largely due to the impact of our development program in late 2019 and into the first quarter of this year. Our California production of 23.5 MBoe/d for the sixnine months September 30, 2020 increased 9% compared to the nine months ended JuneSeptember 30, 2018 from approximately 35.1 MBoe/d2019 where the majority of our capital in 2019 and 2020 was spent. Of the 23 California wells drilled in the first half of 2020, twelve were producing wells, nine were delineation and two were injector wells. This overall increase was also impacted by the same issues identified above in the third quarter to second quarter 2020 section. The production in Utah and Colorado decreased 16% for the sixnine months ended JuneSeptember 30, 2017, including the successor and predecessor periods. The decrease primarily reflected the decreased natural gas and NGL volumes from the sale of the approximately 78% non-operating, working interest in the Hugoton natural gas field in July 2017, partially offset by the additional oil volumes from the Hill Acquisition. Also contributing2020 compared to the decrease,same period in 2019, primarily due to a lesser degree, was the delayed impactlack of increasing capital after our emergence from bankruptcy in early 2017 following the reduced development capital spending in 2016expenditures and early 2017.

natural decline.
Balance Sheet Analysis
31

The changes in our balance sheet from December 31, 2017 to June 30, 2018 are discussed below.
 Berry Corp. (Successor)
 June 30, 2018 December 31, 2017
 (in thousands)
Cash and cash equivalents$3,600
 $33,905
Accounts receivable, net$56,860
 $54,720
Restricted cash$19,710
 $34,833
Other current assets$14,981
 $14,066
Property, plant & equipment, net$1,397,919
 $1,387,191
Other noncurrent assets$22,086
 $21,687
Accounts payable and accrued liabilities$113,170
 $97,877
Derivative instruments-current and long term$15,010
 $60,165
Liabilities subject to compromise$19,710
 $34,833
Long term debt$457,333
 $379,000
Asset retirement obligation$88,575
 $94,509
Other noncurrent liabilties$12,862
 $3,704
Equity$808,496
 $859,310

See “Liquidity and Capital Resources” for a discussion about the changes in cash and cash equivalents, as well as long term debt.

Restricted cash at June 30, 2018 and December 31, 2017 represents funds set aside to settle the general unsecured creditors claims resulting from our bankruptcy process. The decrease in restricted cash, and the corresponding decrease in liabilities subject to compromise, represents the settlementTable of these claims, the return of undistributed funds in the amount of $9 million and professional fees related to the settlement of these claims.Contents

The increase in accounts payable and accrued liabilities is largely the result of the new interest payment obligations on our 2026 Notes, issued in February of 2018 of $11 million.

The decrease in the derivative liability reflects the early termination and replacement of certain hedge contracts to move from a WTI-based position to a Brent-based position and to align our hedging program with higher current commodity prices.

The increase in long term debt represents the issuance of our 2026 Notes in February 2018 in the principal amount of $400 million and the usage of the proceeds to pay down the $379 million balance on our RBL Facility, partially offset by $66 million of additional RBL Facility borrowings in the second quarter of 2018.

The increase in other noncurrent liabilities represents an additional greenhouse gas liability of $9 million for production during the six months ended June 30, 2018 and which is due for payment more than one year from June 30, 2018.

The decrease in equity reflects the $20 million repurchase from certain general unsecured creditors of the right to receive shares of our common stock in settlement of their claims, the declaration of approximately $11 million in dividends on our Series A Preferred Stock and our results of operations.






Results of Operations
Results of Operations -Three Months Ended September 30, 2020 compared to Three Months Ended June 30, 2018 compared to Three Months Ended March 31, 2018.
2020.
 Berry Corp.
(Successor)		 
 Three Months EndedThree Months Ended  
(in thousands)June 30, 2018March 31, 2018$ Change% Change
Revenues and other:    
Oil, natural gas and NGL sales$137,385
$125,624
$11,761
9 %
Electricity sales5,971
5,453
518
9 %
(Losses) gains on oil and natural gas derivatives(78,143)(34,644)(43,499)126 %
Marketing and other revenues769
851
(82)(10)%
 65,982
97,284
(31,302)(32)%
Expenses and other:    
Lease operating expenses41,517
44,303
(2,786)(6)%
Electricity generation expenses3,135
4,590
(1,455)(32)%
Transportation expenses2,343
2,978
(635)(21)%
Marketing expenses407
580
(173)(30)%
General and administrative expenses12,482
11,985
497
4 %
Depreciation, depletion, amortization and accretion21,859
18,429
3,430
19 %
Taxes, other than income taxes8,715
8,256
459
6 %
(Gains) losses on sale of assets and other, net123
—
123
 
 90,581
91,121
(540)(1)%
Other income and (expenses):    
Interest expense(9,155)(7,796)(1,359)17 %
Other, net(239)27
(266)(985)%
Reorganization items, net456
8,955
(8,499)(95)%
Income (loss) before income taxes(33,537)7,349
(40,886)(556)%
Income tax expense (benefit)(5,476)939
(6,415)(683)%
Net income (loss)(28,061)6,410
(34,471)(538)%
Dividends on Series A Preferred Stock(5,650)(5,650)—
— %
Net income (loss) available to common stockholders$(33,711)$760
$(34,471)(4,536)%
     
Three Months Ended
September 30, 2020June 30, 2020$ Change% Change
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales$92,239 $70,515 $21,724 31 %
Electricity sales8,744 4,884 3,860 79 %
(Losses) gains on oil derivatives(11,564)(42,267)30,703 (73)%
Marketing and other revenues330 321 9 3 %
Total revenues and other$89,749 $33,453 $56,296 168 %
Revenues and Other
Oil, natural gas and NGL sales increased $12by $22 million, or 9%31%, to approximately $137$92 million for the three months ended JuneSeptember 30, 20182020, compared to the three months ended March 31, 2018.June 30, 2020. The increase reflects improvedwas driven by $24 million of higher oil prices and a slight increase in production.partially offset by lower oil volumes.
Electricity sales represent sales to utilities, and increased by approximately $0.5$4 million, or 9%79%, to approximately $6$9 million for the three months ended September 30, 2020 compared to the three months ended June 30, 2020. The increase primarily reflected higher unit sales prices that resulted from a seasonal increase in capacity payments and higher natural gas prices during the third quarter 2020 compared to the second quarter 2020.
Gain or loss on oil derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement gains for the three months ended September 30, 2020 and June 30, 2020 were $36 million and $59 million, respectively. The quarter-over-quarter decrease in settlement gains was driven by higher oil prices relative to the derivative fixed contract prices in the third quarter compared to those of the second quarter of 2020. Each of these quarters had the same average derivative fixed prices and daily notional volumes. The mark-to-market non-cash loss of $48 million for the three months ended September 30, 2020 was due to higher futures prices relative to the derivative fixed prices at September 30, 2020 compared to the non-cash loss of $101 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018. The increase was primarily due to higher seasonal prices.
Losses on oil and natural gas derivatives were approximately $78 million for the three months ended June 30, 2018 compared to losses of approximately $35 million for the three months ended March 31, 2018. The increase represents improved commodity prices relative to the fixed prices of our derivative contracts.

2020.
Marketing and other revenues for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018. Marketing revenues in these periods primarily represent sales of third-party natural gas and were comparable for these periods.the periods presented.
Expenses and other
32
Three Months Ended$ Change% Change
September 30, 2020June 30, 2020
(in thousands, except expenses per Boe)
Expenses and other:
Lease operating expenses$45,243 $40,733 $4,510 11 %
Electricity generation expenses4,217 3,022 1,195 40 %
Transportation expenses1,768 1,789 (21)(1)%
Marketing expenses326 280 46 16 %
General and administrative expenses19,173 18,777 396 2 %
Depreciation, depletion and amortization35,905 37,512 (1,607)(4)%
Taxes, other than income taxes9,913 10,449 (536)(5)%
(Gain) losses on natural gas derivatives(15,784)925 (16,709)n/a
Other operating expenses (income)1,648 (1,192)2,840 n/a
Total expenses and other102,409 112,295 (9,886)(9)%
Other (expenses) income:
Interest expense(8,391)(8,676)285 (3)%
Other, net(3)(6)3 (50)%
Loss before income taxes(21,054)(87,524)66,470 (76)%
Income tax (benefit) expense(2,190)(22,623)20,433 (90)%
Net loss$(18,864)$(64,901)$46,037 (71)%
Expenses per Boe:(1)
Lease operating expenses$17.83 $15.37 $2.46 16 %
Electricity generation expenses1.66 1.14 0.52 46 %
Electricity sales(1)
(3.45)(1.84)(1.61)88 %
Transportation expenses0.69 0.67 0.02 3 %
Transportation sales(1)
— (0.01)0.01 (100)%
Marketing expenses0.13 0.11 0.02 18 %
Marketing revenues(1)
(0.13)(0.11)(0.02)18 %
Derivatives settlements paid for gas purchases(1)
0.24 2.78 (2.54)(91)%
Total operating expenses$16.97 $18.11 $(1.14)(6)%
Total unhedged operating expenses(2)
$16.73 $15.33 $1.40 9 %
Total non-energy operating expenses(4)
$13.34 $12.81 $0.53 4 %
Total energy operating expenses(5)
$3.65 $5.30 $(1.65)(31)%
General and administrative expenses(3)
$7.56 $7.09 $0.47 7 %
Depreciation, depletion and amortization$14.15 $14.16 $(0.01)— %
Taxes, other than income taxes$3.91 $3.94 $(0.03)(1)%
__________
33
(1)    We report sales of electricity, transportation and marketing and transportation activities (as applicable)sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales reported in "Other Revenues", relate to water and other liquids that we transport on our systems on behalf of third parties.
parties and have not been significant to date. Operating expenses as defined above, decreased to $16.89also include the effect of derivative settlements (received or paid) for gas purchases.
(2)    Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3)    Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $2.08 per Boe for the quarter ended June 30, 2018 from $19.61 per Boe for the quarter ended March 31, 2018, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $3 million, or 6%, to approximately $42 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018. The decrease was primarily due to lower well servicing activity, lower fuel gas costs and increased oil inventory caused by market disruptions in Utah in the quarter ended June 30, 2018. For the same reasons, lease operating expenses per Boe decreased to $17.24$1.77 per Boe for the three months ended September 30, 2020 and June 30, 2018 from $18.80 per Boe for the three months ended March 31, 2018.
Electricity generation expenses decreased by approximately $1.5 million or 32% for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to lower fuel gas costs and reduced cogen operating costs due to replacement of a third party service provider with internal staffing.
Transportation expenses decreased by approximately $0.6 million, or 21%, to approximately $2 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018, primarily due to reduced costs for use of certain third-party systems.
Marketing expenses for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018.
General and administrative expenses increased by approximately $0.5 million, or 4%, to approximately $12 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to increased costs related to preparing to be a public company. The increase in absolute dollars incurred resulted in slightly higher general and administrative expenses of $5.18 per Boe for the three months ended June 30, 2018, compared to $5.09 per Boe for the three months ended March 31, 2018. For the three months ended June 30, 2018 and March 31, 2018, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.7 million and $2.0 million, respectively, and non-cash stock compensation costs of approximately $1.3 million and $1.0 million,2020, respectively.
Depreciation, depletion(4)    Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and amortization ("DD&A") increased by approximately $3 million, or 19%, to approximately $22 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to increased DD&A rates, slightly higher productiongas purchase derivative settlement (gains) losses.
(5)    Total energy operating expenses equals fuel and increased asset retirement accretion expense.








Taxes, Other Than Income Taxes
 Berry Corp. (Successor)
 Three Months EndedThree Months Ended 
 June 30, 2018March 31, 2018Variance
(in thousands)   
Severance taxes$2,997
$2,764
$233
Ad valorem and property taxes3,141
3,417
(276)
Greenhouse gas allowances2,577
2,075
502
 $8,715
$8,256
$459
    
    
For the three months ended June 30, 2018 compared to the three months ended March 31, 2018, greenhouse gas allowance costs increased due to the higher unit cost and increased activity.
Other income and (expenses)
 Berry Corp.
(Successor)
 Three Months EndedThree Months Ended 
 June 30, 2018March 31, 2018Variance
(in thousands)   
Interest expense, net of amounts capitalized$(9,155)$(7,796)$(1,359)
Other, net(239)27
(266)
 $(9,394)$(7,769)$(1,625)
Interest expense increased for the three months ended June 30, 2018 by $1.4 million or 17%, compared to the three months ended March 31, 2018, due to increased borrowings on the RBL Facility and three months of the interest on the 2026 Notes in the second quarter versus one and a half months in the first quarter.
The following table summarizes the components of reorganization items included in the statement of operations:
 Berry Corp. (Successor)
 Three Months EndedThree Months Ended 
(in thousands)June 30, 2018March 31, 2018Variance
Return of Undistributed Funds from Cash Distribution Pool$—
$9,000
$(9,000)
Refund of pre-emergence prepaid costs—
579
(579)
Legal and other professional advisory fees(1,178)(624)(554)
Gain on resolution of pre-emergence liabilities1,634
—
1,634
 $456
$8,955
$(8,499)
Reorganization items, net consisted of a gain of approximately $0.5 million for the three months ended June 30, 2018. The gain was primarily due to the resolution of certain pre-emergence liabilities, partially offset by legal and other professional fees. For the three months ended March 31, 2018, the gain of $9 million reflected the return of undistributed funds reserved forpurchase derivative settlement of claims of general unsecured creditors.(gains) losses less electricity sales.

Income taxes
The three months ended June 30, 2018 had a $5.5 million tax benefit compared to income tax expense of $0.9 million for the three months ended March 31, 2018. The effective tax rate was 16% for the three months ended June 30, 2018 and 13% for the three months ended March 31, 2018.
Results of Operations - Three Months Ended June 30, 2018 compared to Three Months Ended June 30, 2017.
 Berry Corp.
(Successor)		 
 Three Months EndedThree Months Ended  
(in thousands)June 30, 2018June 30, 2017$ Change% Change
Revenues and other:    
Oil, natural gas and NGL sales$137,385
$101,884
$35,501
35 %
Electricity sales5,971
5,712
259
5 %
(Losses) gains on oil and natural gas derivatives(78,143)23,962
(102,105)(426)%
Marketing and other revenues769
3,164
(2,395)(76)%
 65,982
134,722
(68,740)(51)%
Expenses and other:  

 
Lease operating expenses41,517
45,726
(4,209)(9)%
Electricity generation expenses3,135
4,465
(1,330)(30)%
Transportation expenses2,343
9,404
(7,061)(75)%
Marketing expenses407
730
(323)(44)%
General and administrative expenses12,482
22,257
(9,775)(44)%
Depreciation, depletion, amortization and accretion21,859
20,549
1,310
6 %
Taxes, other than income taxes8,715
10,249
(1,534)(15)%
(Gains) losses on sale of assets and other, net123
5
118
2,360 %
 90,581
113,385
(22,804)(20)%
Other income and (expenses):  

 
Interest expense(9,155)(4,885)(4,270)87 %
Other, net(239)2,916
(3,155)(108)%
Reorganization items, net456
713
(257)(36)%
Income (loss) before income taxes(33,537)20,081
(53,618)(267)%
Income tax expense (benefit)(5,476)7,961
(13,437)(169)%
Net income (loss)(28,061)12,120
(40,181)(332)%
Dividends on Series A Preferred Stock(5,650)(5,404)(246)5 %
Net income (loss) available to common stockholders$(33,711)$6,716
$(40,427)(602)%
     
Revenues and Other
Oil, natural gas and NGL sales increased $36 million, or 35% to approximately $137 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017. The increase reflects improved oil prices and an increased mix of oil production compared to gas production as a result of the Hill Acquisition and Hugoton Disposition, partially offset by decreased production on an oil-equivalent basis.

Electricity sales represent sales to utilities and increased by approximately $0.3 million, or 5%, to approximately $6 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. The increase was primarily due to higher volumes sold externally as a result of lower downtime at our cogens in the three months ended June 30, 2018 than the three months ended June 30, 2017.
Losses on oil and natural gas derivatives were approximately $78 million for the three months ended June 30, 2018 compared to approximately $24 million of gains for the three months ended June 30, 2017. Losses on oil and natural gas derivatives for the three months ended June 30, 2018 were primarily due to an increase in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commodity prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues decreased by approximately $2 million, or 76%, to approximately $0.8 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. Marketing revenues in these periods primarily represent sales of third-party natural gas and were comparable for these periods. Other revenues in 2017 comprised mostly helium sales, all of which were derived from our Hugoton asset prior to its disposition in July 2017.
Expenses and Other
WeIn accordance with GAAP, we report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues. However, these revenues are viewed and used internally in calculating operating expenses, which are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
Operating expenses are defined above in “How We Plan and Evaluate Operations”. On a hedged basis, operating expenses, decreased 6% or $1.14 per Boe to $16.97 in the third quarter 2020 from $18.11 in the second quarter 2020. The decrease was largely due to higher electricity sales resulting from higher seasonal capacity payments. During the third quarter 2020, we sustained the cost savings achieved in the first half of 2020, as hedged fuel and non-fuel costs were essentially flat to the second quarter 2020. On an unhedged basis, operating expenses increased by 9% or $1.40 per Boe to $16.73 for the third quarter 2020, compared to $15.33 for the second quarter 2020. This increase was driven by higher unhedged fuel costs in comparison to the second quarter 2020.
Lease operating expenses per Boe increased to $17.83, for the three months ended September 30, 2020, a 16% or $2.46 per Boe increase compared to $15.37 per Boe for the three months ended June 30, 2020 driven by higher unhedged fuel costs related to our California steam operations. Unhedged fuel cost increased $2.31 per Boe, or 65% in the third quarter 2020 from $3.54 for the three months ended June 30, 2020. Non-fuel lease operating expense increased $0.15 per Boe due to lower sales volumes while spending on an absolute dollar basis was $1 million lower including lower facilities gas compression, oil and water processing costs. Lease operating expenses include fuel, maintenance, labor including supervision, vehicles, workover expenses, field office, and tools and supplies. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Electricity generation expenses increased approximately 46% to $1.66 per Boe for the three months ended September 30, 2020, compared to $1.14 per Boe for the three months ended June 30, 2020 due to higher natural gas costs described above and lower sales volumes. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Gains and losses on natural gas purchase derivatives resulted in a $16 million gain for the three months ended September 30, 2020 and a loss of $1 million in the three months ended June 30, 2020. Settlement losses for each of the three months ended September 30, 2020 and June 30, 2020 were $1 million and $7 million, or $0.24 and $2.78 per Boe, respectively, and decreased due to higher gas prices. The mark-to-market valuation gain for the three months ended September 30, 2020 was $17 million compared to a $6 million gain for the prior quarter. Generally, because we are the fixed price payer on these natural gas swaps, increases in the associated futures prices will result in valuation gains.
Transportation expenses were essentially flat at $0.69 per Boe for the three months ended September 30, 2020 compared to $0.67 per Boe for the three months ended June 30, 2020.
Marketing expenses were comparable for the three months ended September 30, 2020 and June 30, 2020.
34
General and administrative expenses increased by $0.4 million, or 2%, to $19 million for the three months ended September 30, 2020, compared to the three months ended June 30, 2020. For the three months ended September 30, 2020 and June 30, 2020, general and administrative expenses included non-cash stock compensation costs of approximately $3.8 million and $4.4 million, respectively, and certain non-recurring costs of approximately $1.5 million and $0.3 million, respectively. Non-cash stock compensation expense declined from the second quarter 2020 due to the awards that expired or were forfeited in the third quarter 2020 and had been fully expensed at that time. The third quarter 2020 non-recurring costs mainly consisted of costs related to the retirement of former Chief Operating Officer ("COO") and hiring of new COO. Less than 10% of our overhead is capitalized and thus excluded from general and administrative expenses.
Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, were $14 million for each of the three month periods ended September 30, 2020 and June 30, 2020. These cost levels include a slight reduction in headcount since early 2020, although none of these reductions are a result of the current economic environment. Please see “-Non-GAAP Financial Measures” for a reconciliation of adjusted general and administrative expense to general and administrative expenses, the most directly comparable financial measures calculated and presented in accordance with GAAP.
DD&A decreased by $2 million or 4% to approximately $36 million for the three months ended September 30, 2020 compared to the three months ended June 30, 2020. This decrease is attributable to the reduced sales volumes period-over-period.
Taxes, Other Than Income Taxes
Three Months Ended$ Change% Change
September 30, 2020June 30, 2020
(per Boe)
Severance taxes$0.82 $0.70 $0.12 17 %
Ad valorem and property taxes1.60 1.39 0.21 15 %
Greenhouse gas allowances1.49 1.85 (0.36)(19)%
Total taxes other than income taxes$3.91 $3.94 $(0.03)(1)%
Taxes, other than income taxes, decreased in the three months ended September 30, 2020 by $0.03 per Boe, or 1%, to $3.91. Greenhouse gas ("GHG") costs were lower in the third quarter of 2020 as the prices remained relatively flat while the emission volumes declined. During the third quarter 2020, we experienced higher property tax rates, as well as higher severance tax rates due to the expiration of certain deductions. These changes were also impacted by the decrease in sales volumes in the third quarter 2020.
Other Operating (Income) Expenses
Other operating expenses for the three months ended September 30, 2020 was $2 million comprised mainly of excess abandonment costs and excess storage capacity obtained in response to global oil storage concerns. Other operating income of $1 million for the three months ended June 30, 2020 included refunds from sales taxes paid in prior years and resolved claims from our prior parent company's bankruptcy.
Interest Expense
Interest expense was relatively flat at $8 million for each of the three months ended September 30, 2020 and June 30, 2020.
Income Tax (Benefit) Expense
Our effective tax rate was approximately 10% and 26% for the three months ended September 30, 2020 and June 30, 2020, respectively. The rate in the third quarter 2020 was negatively impacted by adjustments to our
35
valuation allowance during the quarter related to current year losses and expected future realizability of deferred tax assets.

Three Months Ended September 30, 2020 compared to Three Months Ended September 30, 2019.
Three Months Ended
September 30,
$ Change% Change
20202019
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales$92,239 $141,250 $(49,011)(35)%
Electricity sales8,744 7,460 1,284 17 %
(Losses) gains on oil derivatives(11,564)45,509 (57,073)n/a
Marketing and other revenues330 453 (123)(27)%
Total revenues and other$89,749 $194,672 $(104,923)(54)%
Revenues and Other
Oil, natural gas and NGL sales decreased by $49 million, or 35% to approximately $92 million for the three months ended September 30, 2020 when compared to the three months ended September 30, 2019. This variance was driven by $40 million of lower commodity prices, as well as $9 million of lower volumes.
Electricity sales represent sales to utilities, and increased by $1.3 million, or 17%, to approximately $9 million for the three months ended September 30, 2020 when compared to the three months ended September 30, 2019. The increase was equally split between higher unit sales prices and higher sales volumes.
Gain or loss on oil derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement gains for the three months ended September 30, 2020 and September 30, 2019 were $36 million and $17 million, respectively. The quarter-over-quarter increase in settlement gains was driven by lower oil prices relative to our derivative fixed contract prices and more volumes hedged in the third quarter of 2020 compared to the third quarter of 2019. The mark-to-market non-cash loss of $48 million for the three months ended September 30, 2020 was due to higher futures prices relative to our derivative fixed contract prices at September 30, 2020. The mark-to-market non-cash gain of $29 million for the three months ended September 30, 2019, was primarily due to lower futures prices relative to our derivative fixed contract prices at September 30, 2019.
Marketing and other revenues were comparable for the periods presented.
36
Three Months Ended
September 30,
$ Change% Change
20202019
(in thousands, except expenses per Boe)
Expenses and other:
Lease operating expenses$45,243 $50,957 $(5,714)(11)%
Electricity generation expenses4,217 3,781 436 12 %
Transportation expenses1,768 2,067 (299)(14)%
Marketing expenses326 398 (72)(18)%
General and administrative expenses19,173 16,434 2,739 17 %
Depreciation, depletion and amortization35,905 27,664 8,241 30 %
Taxes, other than income taxes9,913 9,249 664 7 %
(Gain) losses on natural gas derivatives(15,784)3,008 (18,792)n/a
Other operating expenses (income)1,648 (550)2,198 n/a
Total expenses and other102,409 113,008 (10,599)(9)%
Other (expenses) income:
Interest expense(8,391)(8,597)206 (2)%
Other, net(3)(77)74 (96)%
Reorganization items, net— (170)170 (100)%
(Loss) income before income taxes(21,054)72,820 (93,874)n/a
Income tax (benefit) expense(2,190)20,171 (22,361)n/a
Net (loss) income$(18,864)$52,649 $(71,513)n/a
Expenses per Boe:(1)
Lease operating expenses$17.83 $18.74 $(0.91)(5)%
Electricity generation expenses1.66 1.39 0.27 19 %
Electricity sales(1)
(3.45)(2.74)(0.71)26 %
Transportation expenses0.69 0.76 (0.07)(9)%
Transportation sales(1)
— (0.01)0.01 (100)%
Marketing expenses0.13 0.15 (0.02)(13)%
Marketing revenues(1)
(0.13)(0.15)0.02 (13)%
Derivatives settlements paid for gas purchases(1)
0.24 0.77 (0.53)(69)%
Total operating expenses$16.97 $18.90 $(1.93)(10)%
Total unhedged operating expenses(2)
$16.73 $18.13 $(1.40)(8)%
Total non-energy operating expenses(4)
$13.34 $14.09 $(0.75)(5)%
Total energy operating expenses(5)
$3.65 $4.81 $(1.16)(24)%
General and administrative expenses(3)
$7.56 $6.04 $1.52 25 %
Depreciation, depletion and amortization$14.15 $10.17 $3.98 39 %
Taxes, other than income taxes$3.91 $3.40 $0.51 15 %
__________
37
(1)    We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses as defined above, decreased to $16.89also include the effect of derivative settlements (received or paid) for gas purchases.
(2)    Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3)    Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $2.08 per Boe for the quarter ended June 30, 2018 from $17.20 per Boe for the quarter ended June 30, 2017, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $4 million, or 9%, to approximately $42 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. The decrease was primarily due to a decrease in the price of fuel gas used in operations. Further, lease operating expenses per Boe increased to $17.24$0.91 per Boe for the three months ended JuneSeptember 30, 2018 from $14.622020 and September 30, 2019, respectively.
(4)    Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(5)    Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
Expenses and Other
Operating expenses, including hedge effects, decreased by 10% or $1.93 per Boe to $16.97 per Boe for the third quarter 2020 compared to $18.90 per Boe for the third quarter 2019. This decrease included $0.91 per Boe lower lease operating expenses and $0.44 of higher electricity sales margin and $0.53 per Boe of more favorable gas hedge settlements in 2020. Additionally, operating expenses, on an unhedged basis, were 8%, or $1.40 per Boe lower for the three months ended September 30, 2020 compared to the three months ended September 30, 2019 due to these same non-hedge factors.
As a result of our 2020 cost savings and efficiency initiatives, we experienced a positive and substantial impact on lease operating expenses in 2020 when compared to 2019. Lease operating expenses were $17.83 per Boe for the three months ended JuneSeptember 30, 2017, primarily due to increased oil production to 80% of total production from 56% of total production as2020, a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) which adversely impacted costs per Boe. Replacing low cost natural gas production with oil production in 2017 had a disproportionate impact (oil volume rose 10% and gas volume decreased 62% but cost5% or $0.91 per Boe rose 18%), on our costs per Boe when comparing these respective periods.
Electricity generation expenses decreased approximately $1 million or 30%reduction compared to $3 million$18.74 for the three months ended JuneSeptember 30, 20182019. Non-fuel lease operating expense decreases included $0.65 of lower costs related to maintenance, as well as $0.46 in facilities gas compression and the three months ended June 30, 2017, primarily due to a decreaseoil and water processing costs. On an absolute dollar basis, non-fuel lease operating expenses declined $4 million in the price of natural gas.
Transportation expenses decreased by approximately $7 million, or 75%, to approximately $2 million for the three months ended June 30, 2018,third quarter 2020 compared to the three months ended June 30, 2017, primarilysame period last year. Lease operating fuel cost related to our California steam operations were unchanged during the third quarter 2020 from the same quarter 2019 due to the Hugoton Disposition of gas properties,more efficient steam consumption per Boe, which required significant transportation expense because gas transportation is generally borne by the seller and oil transportation costs are borne by the buyer.
Marketing expenses decreased $0.3 million or 44% to $0.4 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the decrease inoffset higher natural gas prices. Lease operating expenses include fuel, maintenance, labor including supervision, vehicles, workover expenses, field office, tools and supplies. Fuel costs excluded the effects of natural gas derivative settlements discussed below.
General and administrativeElectricity generation expenses decreased byincreased approximately $10 million, or 44%,19% to approximately $12 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the management change in conjunction with our emergence from bankruptcy. The reduction in absolute dollars spent, as well as lower production volumes resulted in lower general and administrative expenses of $5.18$1.66 per Boe for the three months ended JuneSeptember 30, 2018,2020 from $1.39 per Boe for the same period in 2019 primarily due to higher natural gas costs previously mentioned, as well as the impact of lower Boe volumes. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements.
Gains and losses on natural gas purchase derivatives for the three months ended September 30, 2020 and September 30, 2019 resulted in a gain of $16 million and a loss of $3 million, respectively. Settlement losses for each of the three months ended September 30, 2020 and 2019, were $1 million and $2 million, or $0.24 and $0.77 per Boe, respectively, and decreased due to higher gas prices during 2020. The mark-to-market valuation gain for the three months ended September 30, 2020 was $17 million compared to $7.11$1 million of loss for the same period in 2019, consistent with the changes in futures prices at the end of each period. Because we are the fixed price payer on these natural gas swaps, generally, increases in the associated price index creates valuation gains.
Transportation expenses were down $0.07 per Boe to $0.69 for the three months ended September 30, 2020 compared to the three months ended September 30, 2019 as a result of lower natural gas sales volumes.
Marketing expenses decreased 13% to $0.13 per Boe for the three months ended JuneSeptember 30, 2017.2020, compared to $0.15 per Boe for the three months ended September 30, 2019 mostly due to lower gas prices.
General and administrative expenses increased $3 million, or 17%, to approximately $19 million for the three months ended September 30, 2020 compared to the three months ended September 30, 2019. For the three months
38
ended JuneSeptember 30, 2018,2020 and September 30, 2019, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.7 million and non-cash stock compensation costs of approximately $1.3 million. For the three months ended June 30, 2017,$3.8 million and $2.3 million, respectively, and non-recurring costs of approximately $1.5 million and $0.2 million, respectively.
Adjusted general and administrative expenses, included non-recurring restructuring and other costs of approximately $17 million and nowhich exclude non-cash stock compensation costs.costs and non-recurring costs, were $14 million for each of the three month periods ended September 30, 2020 and September 30, 2019.
DD&A increased by approximately $1$8 million, or 6%30%, to approximately $22$36 million for the three months ended JuneSeptember 30, 20182020 compared to the three months ended JuneSeptember 30, 2017,2019, primarily due to higher depreciation and depletion rates for 2020, partially offset by lower sales volumes. On a per Boe basis, period-over-period DD&A increased $3.98 to $14.15 from $10.17 due to our increasing capital development program throughout 2019 and the Hill Acquisition. The Hill property which had a higher depletion rate than the Hugoton field.



first quarter of 2020, compared to prior periods.
Taxes, Other Than Income Taxes
Berry Corp. (Successor)
Three Months Ended
September 30,
$ Change% Change
Three Months Ended 20202019
June 30, 2018June 30, 2017Variance(per Boe)
(in thousands) 
Severance taxes$2,997
$2,466
$531
Severance taxes$0.82 $0.67 $0.15 22 %
Ad valorem and property taxes3,141
4,498
(1,357)Ad valorem and property taxes1.60 1.23 0.37 30 %
Greenhouse gas allowances2,577
3,285
(708)Greenhouse gas allowances1.49 1.50 (0.01)(1)%
Total taxes other than income taxesTotal taxes other than income taxes$3.91 $3.40 $0.51 15 %
$8,715
$10,249
$(1,534)
Taxes, other than income taxes decreased by approximately $1.5 million orincreased 15% to $3.91 per Boe for the three months ended JuneSeptember 30, 20182020 compared to the three months ended June 30, 2017 due to (i) an increase in gross sales revenue which is the basis for severance taxes, (ii) lower ad valorem and property taxes due to reduced tax assessments in 2018 and (iii) lower prices for greenhouse gas emission credits, partially offset by an increase in emissions in 2018.
Other income and (expenses)
 Berry Corp. (Successor)
 Three Months EndedThree Months Ended 
 June 30, 2018June 30, 2017Variance
(in thousands)   
Interest expense, net of amounts capitalized$(9,155)$(4,885)$(4,270)
Other, net(239)2,916
(3,155)
 $(9,394)$(1,969)$(7,425)
Interest expense increased$3.40 per Boe for the three months ended JuneSeptember 30, 2018 by approximately $4 million or 87%, compared2019. The increase was largely due to the three months ended June 30, 2017, primarilyhigher property tax rates combined with lower sales volumes, as well as increased severance tax rates due to the additionexpiration of interest expense on the 2026 Notes, which were issuedcertain deductions in February 2018, partially offset by lower interest on the RBL Facility due to the decrease in borrowings period over period.2020.
The following table summarizes the components of reorganization items included in the statement of operations:
Other Operating (Income) Expenses
 Berry Corp. (Successor)
 Three Months EndedThree Months Ended 
(in thousands)June 30, 2018June 30, 2017Variance
Legal and other professional advisory fees(1,178)(3,199)2,021
Gain on resolution of pre-emergence liabilities1,634
3,912
(2,278)
 $456
$713
$(257)
Reorganization items, net consisted of a gain of approximately $0.5 millionOther operating expenses for the three months ended JuneSeptember 30, 2018, compared2020 was $2 million, comprised mainly of excess abandonment costs and excess storage capacity obtained in response to the $0.7 million gainglobal oil storage concerns. Other operating income for the three months ended JuneSeptember 30, 2017. The second quarter 2018 gain2019 were $1 million and consisted mainly of excess abandonment costs.
Interest Expense
Interest expense was primarily due tocomparable in the resolution of certain pre-emergence liabilities, partially offset by legalthree months ended September 30, 2020 and other professional fees. The 2017 gain amount was primarily due to a resolution of certain pre-emergence liabilities of $3.9 million partially offset by legal and professional fees to resolve outstanding bankruptcy-related claims.September 30, 2019.
Income tax benefit was $5.5 millionReorganization items, net
Reorganization items, net were not material for the three months ended JuneSeptember 30, 2018, compared to the income2020 and September 30, 2019.
Income Tax (Benefit) Expense
Our effective tax expense of $8.0 millionrate was 10% for the three months ended JuneSeptember 30, 2017 due to recording pre-tax loss in 2018 compared to pre-tax income in 2017. The decrease in the effective tax rates from 40% in 2017 to 16% in 2018 was primarily a result of the new tax laws for 2018.

Results of Operations - Six Months Ended June 30, 20182020 compared to the Six Months ended June 30, 2017 , including the successor and predecessor periods.
Our results of operations28% for the sixthree months ended JuneSeptember 30, 2017 are reflected2019. The rate in the tablesthird quarter 2020 was negatively impacted by adjustments to our valuation allowance during the quarter related to current year losses and narrative discussion that follow in two distinct periods, the four months ended Juneexpected future realizability of deferred tax assets.
39
Nine Months Ended September 30, 2017 and the two months ended February 28, 2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations2020 compared to the six months ended JuneNine Months Ended September 30, 2017 are used to provide comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for comparing the periods presented.
2019.
 Berry Corp.
(Successor)		Berry LLC (Predecessor)  
 (a)(b)(c)(a)-((b)+(c)) 
 Six Months EndedFour Months EndedTwo Months Ended  
 June 30, 2018June 30, 2017February 28, 2017$ Change% Change
(in thousands)     
Revenues and other:     
Oil, natural gas and NGL sales$263,010
$135,562
$74,120
$53,328
25 %
Electricity sales11,423
6,603
3,655
1,165
11 %
(Losses) gains on oil and natural gas derivatives(112,787)48,085
12,886
(173,758)(285)%
Marketing and other revenues1,619
4,127
2,057
(4,565)(74)%
 163,265
194,377
92,718
(123,830)(43)%
Expenses and other:   —
 
Lease operating expenses85,819
58,790
28,238
(1,209)(1)%
Electricity generation expenses7,725
5,613
3,197
(1,085)(12)%
Transportation expenses5,321
13,059
6,194
(13,932)(72)%
Marketing expenses987
1,000
653
(666)(40)%
General and administrative expenses24,466
31,800
7,964
(15,298)(38)%
Depreciation, depletion, amortization and accretion40,288
27,571
28,149
(15,432)(28)%
Taxes, other than income taxes16,972
13,330
5,212
(1,570)(8)%
(Gains) losses on sale of assets and other, net123
5
(183)301
(169)%
 181,701
151,168
79,424
(48,891)(21)%
Other income and (expenses):   —
 
Interest expense(16,951)(6,600)(8,245)(2,106)14 %
Other, net(212)2,916
(63)(3,065)(107)%
Reorganization items, net9,411
(593)(507,720)517,724
(102)%
Income (loss) before income taxes(26,188)38,932
(502,734)437,614
(94)%
Income tax expense (benefit)(4,537)15,435
230
(20,202)(129)%
Net income (loss)(21,651)23,497
(502,964)457,816
(95)%
Dividends on Series A Preferred Stock(11,301)(7,196)—
(4,105)57 %
Net income (loss) available to common stockholders$(32,952)$16,301
$(502,964)$453,711
(93)%

Nine Months Ended
September 30,		$ Change% Change
20202019
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales$284,852 $409,259 $(124,407)(30)%
Electricity sales19,089 22,553 (3,464)(15)%
Gains on oil derivatives157,398 7,546 149,852 n/a
Marketing and other revenues1,128 1,918 (790)(41)%
Total revenues and other$462,467 $441,276 $21,191 5 %
Revenues and Other
Oil, natural gas and NGL sales increased approximately $53decreased by $124 million, or 25%30% to approximately $263$285 million for the sixnine months ended JuneSeptember 30, 20182020 when compared to the sixnine months ended JuneSeptember 30, 2017, including the successor and predecessor periods.2019. The increase reflects improveddecrease was driven by $139 million attributable to lower oil prices and an increased mix of oil production compared$4 million attributable to lower gas production as a result of the Hill Acquisition and Hugoton Disposition,prices. These decreases were partially offset by decreased overall production, as well as slightly lower gas prices.approximately $21 million attributable to higher oil volumes.
Electricity sales which represent sales to utilities and increased by approximately $1decreased $3 million or 11%,15% to approximately $11$19 million for the sixnine months ended JuneSeptember 30, 2018,2020 when compared to the sixnine months ended JuneSeptember 30, 2017, including2019. The decrease was mostly due to lower unit sales prices that were driven by lower natural gas prices.
Gain or loss on oil derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement gains for the successornine months ended September 30, 2020 and predecessor periods,September 30, 2019 were $119 million and $29 million, respectively. The increase in settlement gains was driven by lower oil prices relative to the derivative fixed prices and more volumes hedged in the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. The mark-to-market non-cash gain of $38 million for the nine months ended September 30, 2020 was due to lower futures prices relative to the derivative fixed prices at September 30, 2020. The loss of $21 million for the nine months ended September 30, 2019, was primarily due to higher volumes sold externally as a result of lower downtime at our cogens.
Losses on oil and natural gas derivatives increased to approximately $113 million in the six months ended June 30, 2018, compared to gains of approximately $61 million in the six months ended June 30, 2017, including the successor and predecessor periods. Losses on oil and natural gas derivatives in 2018 were primarily due to an increase in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commodityfutures prices relative to the derivative fixed prices of our derivative contracts.at September 30, 2019.
Marketing and other revenues decreased approximately $5 million or 74%were lower for the sixnine months ended JuneSeptember 30, 2018 when2020, compared to the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, primarily2019 due to the lost helium sales revenue as a resultlower average gas prices.
40
Expenses and other
Nine Months Ended
September 30,		$ Change% Change
20202019
(in thousands, except expenses per Boe)
Expenses and other:
Lease operating expenses$136,727 $156,765 $(20,038)(13)%
Electricity generation expenses11,186 14,705 (3,519)(24)%
Transportation expenses5,379 5,935 (556)(9)%
Marketing expenses1,036 1,670 (634)(38)%
General and administrative expenses57,287 46,932 10,355 22 %
Depreciation, depletion and amortization108,746 75,904 32,842 43 %
Impairment of oil and gas properties289,085 — 289,085 100 %
Taxes, other than income taxes24,714 28,683 (3,969)(14)%
(Gain) losses on natural gas derivatives(2,824)10,342 (13,166)n/a
Other operating expenses2,658 3,814 (1,156)(30)%
Total expenses and other633,994 344,750 289,244 84 %
Other (expenses) income:
Interest expense(25,987)(26,362)375 (1)%
Other, net(15)79 (94)n/a
Reorganization items, net— (426)426 (100)%
(Loss) income before income taxes(197,529)69,817 (267,346)n/a
Income tax expense (benefit)1,536 19,294 (17,758)(92)%
Net (loss) income$(199,065)$50,523 $(249,588)n/a
Expenses per Boe:(1)
Lease operating expenses$17.12 $20.31 $(3.19)(16)%
Electricity generation expenses1.40 1.91 (0.51)(27)%
Electricity sales(1)
(2.39)(2.92)0.53 (18)%
Transportation expenses0.67 0.77 (0.10)(13)%
Transportation sales(1)
(0.01)(0.03)0.02 (67)%
Marketing expenses0.13 0.22 (0.09)(41)%
Marketing revenues(1)
(0.12)(0.21)0.09 (43)%
Derivatives settlements paid (received) for gas purchases(1)
1.55 0.25 1.30 n/a
Total operating expenses$18.35 $20.28 $(1.93)(10)%
Total unhedged operating expenses(2)
$16.80 $20.03 $(3.23)(16)%
Total non-energy operating expenses(4)
$13.41 $14.75 $(1.34)(9)%
Total energy operating expenses(5)
$4.94 $5.54 $(0.60)(11)%
General and administrative expenses(3)
$7.17 $6.08 $1.09 18 %
Depreciation, depletion and amortization$13.62 $9.84 $3.78 38 %
Taxes, other than income taxes$3.10 $3.72 $(0.62)(17)%
__________
41
(1)    We report sales of electricity, transportation and marketing and transportation activities (as applicable)sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses increased to $18.24also include the effect of derivative settlements (received or paid) for gas purchases.
(2)    Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3)    Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.85 per Boe and $1.18 per Boe for the sixnine months ended JuneSeptember 30, 2018 from $15.782020 and September 30, 2019, respectively.
(4)    Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(5)    Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
Expenses and Other
Operating expenses, including hedge effects, decreased 10% or $1.93 per Boe to $18.35 for the sixnine months ended JuneSeptember 30, 2017 including the successor and predecessor periods, for the reasons described below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses in absolute dollars for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods, reflected lower fuel gas costs offset by higher activity in 2018 compared to 2017. Lease operating expenses per Boe increased to $18.012020 from $20.28 per Boe for the sixnine months ended JuneSeptember 30, 2018, from $13.692019 due to $3.19 per Boe lower lease operating expenses, partially offset by $1.30 per Boe of higher gas hedge settlement losses and $0.02 decrease in electricity sales margin. Additionally, operating expenses, on an unhedged basis were $16.80 per Boe for the sixnine months ended JuneSeptember 30, 2017, including2020 which was approximately 16% lower than the successor and predecessor periods. The increase in oil productionnine months ended September 30, 2019 due to 80% of total production from 56% as a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) adversely impacted coststhese same non-hedge factors.
Lease operating expenses decreased to $17.12 per Boe in 2018for the nine months ended September 30, 2020, a 16% or $3.19 per Boe reduction compared to 2017.$20.31 for the nine months ended September 30, 2019. The decrease was driven primarily by lower unhedged fuel prices related to our California steam operations and other cost savings. Unhedged fuel cost decreased $2.01 per Boe during the nine months ended September 30, 2020 from $6.81 in the same period of 2019 as natural gas prices declined 30%. Compared to the nine months ended September 30, 2019, the 2020 lease operating non-fuel expenses decreased $1.18, or $6 million on an absolute dollar basis, primarily due to cost savings initiatives and efficiency measures implemented beginning in the second quarter of 2020. These initiatives resulted in lower maintenance and outside services costs of $1.22 per Boe when compared to the nine months ended September 30, 2019. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Electricity generation expenses were comparabledecreased approximately 27% to $1.40 per Boe for the sixnine months ended JuneSeptember 30, 2018 and2020 from $1.91 per Boe for the sixsame period in 2019 primarily driven by lower fuel cost. Decreased fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements discussed elsewhere.
Gain or loss on natural gas purchase derivatives for the nine months ended JuneSeptember 30, 2017, including2020 and September 30, 2019 was a gain of $3 million and a loss of $10 million, respectively. The settlement loss for the successornine months ended September 30, 2020 was $12 million, or $1.55 per Boe, compared to a settlement loss of $2 million, or $0.25 per Boe for same period in 2019, consistent with the changes in futures prices at the end of each period. The mark-to-market valuation gain or loss for each of the periods ended September 30, 2020 and predecessor periods.September 30, 2019 was a gain of $15 million and a loss of $8 million respectively.
Transportation expenses decreased by approximately $14 million or 72%13% to $0.67 per Boe for the sixnine months ended JuneSeptember 30, 20182020, compared to $0.77 per Boe for the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, primarily2019, mainly due to the Hugoton disposition of gas properties, which required significant transportation expense because gas transportation is generally borne by the seller and oil transportation costs are borne by the buyer.lower volumes shipped from our Rockies assets.
Marketing expenses decreased $0.7 million or 40%41% to $0.13 per Boe for the sixnine months ended JuneSeptember 30, 20182020, compared to $0.22 per Boe for the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, primarily2019 due to lower gas prices. Marketing expenses in these periods, which exclude the decrease ineffects of hedging, represented the cost of natural gas prices.purchased from and sold to third parties.
42
General and administrative expenses decreasedincreased by approximately $15$10 million, or 22%, for the sixnine months ended JuneSeptember 30, 20182020 compared to the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, in terms of absolute dollars, primarily due to the reduced spending on non-recurring restructuring and other costs, slightly offset by increased headcount-related costs. This activity was consistent with our post-emergence efforts to build out our corporate structure while reducing restructuring costs. This also resulted in a decrease in general and administrative expenses per Boe to $5.14 in 2018 from $6.25 in 20172019. For the sixnine months ended JuneSeptember 30, 20182020 and 2017,September 30, 2019, general and administrative expenses included non-recurring restructuringnon-cash stock compensation costs of approximately $11 million and other$6 million, respectively, and non-recurring costs of approximately $4 million and $24$3 million, respectively,respectively.
Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, were $43 million for the nine months ended September 30, 2020 compared to $38 million for the nine months ended September 30, 2019. The year-over-year increases in both general and administrative expenses and adjusted general and administrative expenses were primarily due to increased costs associated with supporting the company's growth, including the expansion of approximately $2.3 millionour corporate affairs department and none, respectively.activities whose purpose is to support our efforts and participation in the regulatory, political and legislative process primarily in California.
Depreciation, depletion and amortization decreased by approximately $15DD&A increased $33 million, or 28%43%, to approximately $109 million for the sixnine months ended JuneSeptember 30, 20182020 compared to the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods,2019, primarily due to the increase inincreased production and higher depreciation and depletion rates for 2020. On a per Boe basis, period-over-period DD&A increased $3.78 to $13.62 from $9.84 due to our increasing capital development program throughout 2019 and the first quarter of 2020, compared to prior periods.
Impairment of oil and gas reservesproperties
As discussed above, we recorded a non-cash pre-tax asset impairment charge of $289 million on properties in 2018, which resulted in lower DD&A ratesUtah and certain California locations for the fair market revaluation of our assets in fresh start accounting which resulted in a lower depreciable asset base in the periods following our emergence from bankruptcy.

nine months ended September 30, 2020.
Taxes, Other Than Income Taxes
Berry Corp. (Successor)Berry LLC (Predecessor) Nine Months Ended
September 30,		$ Change% Change
Six Months EndedFour Months EndedTwo Months Ended 20202019
June 30, 2018June 30, 2017February 28, 2017Variance(per Boe)
(a)(b)(c)(a)-((b)+(c))
(in thousands)   
Severance taxes$5,761
$3,611
$1,540
$610
Severance taxes$0.74 $0.57 $0.17 30 %
Ad valorem and property taxes6,558
5,572
2,108
(1,122)Ad valorem and property taxes1.46 1.31 0.15 11 %
Greenhouse gas allowances4,653
4,146
1,564
(1,057)Greenhouse gas allowances0.90 1.84 (0.94)(51)%
Total taxes other than income taxesTotal taxes other than income taxes$3.10 $3.72 $(0.62)(17)%
$16,972
$13,329
$5,212
$(1,569)
Taxes, other than income taxes decreased by approximately $1.5 million or 15%$0.62 to $3.10 per Boe for the sixnine months ended JuneSeptember 30, 20182020 compared to $3.72 per Boe for the nine months ended September 30, 2019. The decrease was largely due to lower greenhouse gas prices during 2020 including some allowance purchases we made at low prices due to a temporary market dislocation in the first quarter 2020. During 2020, we experienced higher property tax rates, as well as higher severance tax rates due to the expiration of certain deductions. These changes were also positively impacted by the increase in sales volumes during the nine months ended September 30, 2020 compared to the sixsame period in 2019.
Other Operating Expenses (Income)
Other operating expenses for the nine months ended JuneSeptember 30, 2017,2020 were $3 million including the successor and predecessor periods,excess abandonment costs, drilling rig standby costs due to (i) an increase in gross sales revenue which is the basis for severance taxes (ii) lower ad valoremdeferred drilling activity, and property taxes due to reduced tax assessments in 2018 and (iii) lower prices for greenhouse gas emission credits,inventory storage costs, partially offset by an increaserefunds from sales taxes paid in emissions in 2018.prior years and resolved claims from our prior parent company's bankruptcy. Other operating expenses for the nine months ended September 30, 2019 were $4 million and were mostly comprised of excess abandonment costs.
Other income and (expenses)
 Berry Corp.
(Successor)		Berry LLC (Predecessor) 
 Six Months EndedFour Months EndedTwo Months Ended 
 June 30, 2018June 30, 2017February 28, 2017Variance
 (a)(b)(c)(a)-((b)+(c))
(in thousands)    
Interest expense, net of amounts capitalized$(16,951)$(6,600)$(8,245)$(2,106)
Other, net(212)2,916
(63)(3,065)
 $(17,163)$(3,684)$(8,308)$(5,171)
Interest Expense
Interest expense increased by $2 million or 14%was comparable in the nine months ended September 30, 2020 and September 30, 2019.
43
Reorganization items, net
Reorganization items, net were not material for the sixnine months ended September 30, 2020 and September 30, 2019.
Income Tax Expense (Benefit)
Our effective tax rate was (1)% and 28% for the nine months ended September 30, 2020 and September 30, 2019, respectively. The rate in 2020 was negatively impacted as we have recorded a valuation allowance on a large portion of our tax credits recorded in 2019 and on other deferred tax assets as a result of current year losses and changes during the year related to future realizability.
Non-GAAP Financial Measures
Adjusted EBITDA, Levered Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses
Adjusted Net Income (Loss) is not a measure of net income (loss), Levered Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either, 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.
We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring 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 to sustain production levels and for 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.
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.
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.
44
Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and restructuring and other non-recurring costs. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period.
We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature. Adjusted General and Administrative Expenses should not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures of other companies.
The following tables present reconciliations of the non-GAAP financial measures Adjusted EBITDA 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.
Three Months EndedNine Months Ended
September 30, 2020June 30, 2020September 30, 2019September 30, 2020September 30, 2019
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net (loss) income$(18,864)$(64,901)$52,649 $(199,065)$50,523 
Add (Subtract):
Interest expense8,391 8,676 8,597 25,987 26,362 
Income tax (benefit) expense(2,190)(22,623)20,171 1,536 19,294 
Depreciation, depletion and amortization35,905 37,512 27,664 108,746 75,904 
Impairment of oil and gas properties— — — 289,085 — 
Derivative (gains) losses(4,220)43,192 (42,501)(160,222)2,796 
Net cash received for scheduled derivative settlements35,476 51,874 15,153 106,975 26,731 
Other operating expense (income)1,648 (1,192)(550)2,658 3,814 
Stock compensation expense3,896 4,579 2,360 11,397 6,277 
Non-recurring costs1,473 316 219 3,651 3,061 
Reorganization items, net— — 170 — 426 
Adjusted EBITDA$61,515 $57,433 $83,931 $190,748 $215,188 
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Three Months EndedNine Months Ended
September 30, 2020June 30, 2020September 30, 2019September 30, 2020September 30, 2019
(in thousands)
Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided by (used in) operating activities:
Net cash provided by operating activities$57,997 $41,939 $68,774 $144,419 $164,267 
Add (Subtract):
Cash interest payments14,435 648 14,864 29,962 30,136 
Cash income tax payments221 — — 222 — 
Non-recurring costs1,473 316 219 3,651 3,061 
Other changes in operating assets and liabilities(12,611)14,530 74 12,494 17,724 
Adjusted EBITDA$61,515 $57,433 $83,931 $190,748 $215,188 
Subtract:
Capital expenditures - accrual basis(5,426)(16,528)(63,488)(61,368)(169,217)
Interest expense(8,391)(8,676)(8,597)(25,987)(26,362)
Cash dividends declared— — (9,720)(9,564)(29,502)
Levered Free Cash Flow(1)
$47,698 $32,229 $2,126 $93,829 $(9,893)
__________
(1)    Levered Free Cash Flow, as defined by the Company, includes cash received for scheduled derivative settlements of $35 million, $52 million and $15 million for the three months ended September 30, 2020, June 30, 2018, compared to2020 and September 30, 2019, respectively. Levered Free Cash Flow, as defined by the sixCompany, includes cash received for scheduled derivative settlements of $107 million and $27 million for the nine months ended JuneSeptember 30, 2017, including successor2020 and predecessor periods, due to the additional 7% interest expense on the 2026 Notes which were issued in February 2018, partially offset by lower interest on the RBL Facility due to the decrease in borrowings from $385 million at June 30, 2017 to $66 million at June 30, 2018. Other, net for the four months ended June 30, 2017 primarily represents the refund of an overpayment on taxes from a prior year.











2019, respectively.
The following table summarizespresents a reconciliation of the componentsnon-GAAP financial measure Adjusted Net Income (Loss) to the GAAP financial measure of reorganizationnet income (loss).
Three Months EndedNine Months Ended
September 30, 2020June 30, 2020September 30, 2019September 30, 2020September 30, 2019
(in thousands)
Adjusted Net Income (Loss) reconciliation to net (loss) income:
Net (loss) income$(18,864)$(64,901)$52,649 $(199,065)$50,523 
Add (Subtract): discrete income tax items(2,394)— — 44,306 — 
Add (Subtract):
(Gains) losses on oil and natural gas derivatives(4,220)43,192 (42,501)(160,222)2,796 
Net cash received for scheduled derivative settlements35,476 51,874 15,153 106,975 26,731 
Other operating expenses (income)1,648 (1,192)(550)2,658 3,814 
Impairment of oil and gas properties— — — 289,085 — 
Non-recurring costs1,473 316 219 3,651 3,061 
Reorganization items, net— — 170 — 426 
Total additions, net34,377 94,190 (27,509)242,147 36,828 
Income tax (expense) benefit of adjustments at effective tax rate(1)
333 (24,680)7,620 (51,152)(10,164)
Adjusted Net Income$13,452 $4,609 $32,760 $36,236 $77,187 
__________
(1)    Excludes discrete income tax items included in the statement of operations:
 Berry Corp. (Successor)Berry LLC (Predecessor) 
 Six Months EndedFour Months EndedTwo Months Ended 
(in thousands)June 30, 2018June 30, 2017February 28, 2017Variance
 (a)(b)(c)(a)-((b)+(c))
Return of Undistributed Funds from Cash Distribution Pool$9,000
$—
$—
$9,000
Legal and other professional advisory fees(1,223)112
(19,481)18,146
Gain on resolution of pre-emergence suspended royalties—
—
421,774
(421,774)
Fresh-start valuation adjustments—
—
(920,699)920,699
Gain on resolution of pre-emergence liabilities1,634
—
—
1,634
Other—
(705)10,686
(9,981)
 $9,411
$(593)$(507,720)$517,724
Reorganization items, net reflected a gain of approximately $9 million for the six months ended June 30, 2018, compared to an expense of approximately $507 million for the six months ended June 30, 2017, including successor and predecessor periods. The gain for the six months ended 2018 was primarily due to a return of $9 million from the funds reserved fortotal additions, net line item and the claimstax effect the discrete income tax items have on the current year effective tax rate.
46
The following table presents a reconciliation of the general unsecured creditorsnon-GAAP financial measure Adjusted General and the resolution of pre-emergence liabilities in the amount of $1.6 million offset by legal and professional fees of $1.2 million.
The loss for the two months ended February 28, 2017 was primarily dueAdministrative Expenses to the applicationGAAP financial measure of fresh-start accounting in conjunction with our emergence from bankruptcy, partially offset by the gain on settlement of liabilities subject to compromise. Reorganization items represent costsgeneral and income directly associated with the Chapter 11 Proceedings and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.
Income tax benefit was $4.5 millionadministrative expenses for the six months ended June 30, 2018, compared to an income tax expense of approximately $15.7 million for the six months ended June 30, 2017, including the successor and predecessor periods, due to recording pre-tax income in 2018 compared to a pre-tax loss in 2017. The decrease in the effective tax rates from 40% in 2017 to 17% in 2018 was primarily a resulteach of the new tax laws for 2018.periods indicated.
For federal and state income tax purposes (with the exception
Three Months EndedNine Months Ended
September 30, 2020June 30, 2020September 30, 2019September 30, 2020September 30, 2019
(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
General and administrative expenses$19,173 $18,777 $16,434 $57,287 $46,932 
Subtract:
Non-cash stock compensation expense (G&A portion)(3,812)(4,380)(2,275)(11,111)(6,067)
Non-recurring costs(1,473)(316)(219)(3,651)(3,061)
Adjusted G&A$13,888 $14,081 $13,940 $42,525 $37,804 
Adjusted general and administrative expenses ($/MBoe)$5.47 $5.31 $5.13 $5.33 $4.90 
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Liquidity and Capital Resources
Currently, we expect our primary sources of liquidity and capital resources will be internally generated free cash flow from operations after debt service, or levered free cash flow,Levered Free Cash Flow, and as needed, borrowings under the RBL Facility, described below. As of September 30, 2020, we had liquidity of $192 million, consisting of $49 million cash in the bank and borrowing availability of $143 million under our RBL Facility. Depending upon market conditionsThe RBL Facility currently has a $200 million borrowing base with a $200 million elected commitment and other factors, we have issued and may issue additional equity and debt securities; however,borrowing availability of $150 million until the next semi-annual borrowing base redetermination that is scheduled to occur in November 2020, at which time we expect our operationsthe availability to continuereturn to generate sufficient levered free cash flow at current commodity prices to fund maintenance operations and organic growth.this elected commitment amount. We currently believe that our liquidity and capital resources will be sufficient to conduct our business and operations for the next 12 months.
In February 2018, we issuedWe currently expect our 2026 Notes, which resultedoperations to continue to generate positive Levered Free Cash Flow in net proceeds to us2020 and for the combined two-year down-cycle through the end of 2021, even at the currently depressed commodity price levels, given our current hedge positions and based on our current operating plans. We currently have essentially all of our expected oil production hedged in the fourth quarter of 2020 at nearly $60 per barrel, as well as additional 2021 hedge positions at nearly $46 per barrel for approximately 19,000 Bbls/d in the first half of 2021 and approximately 11,000 Bbls/d in the second half of 2021 at $46 per barrel. As of September 30, 2020, our oil hedge positions had a fair value of approximately $391 million after deducting expenses$45 million. However, our business, like other producers, has been and is expected to continue to be negatively affected by the ongoing and evolving volatility, uncertainty, and turmoil in the oil and gas industry created by the COVID-19 demand destruction and the initial purchasers’ discount. We usedunknown supply levels caused by OPEC+’s actions, as further discussed under “Business Environment, Market Conditions and Outlook” in this report. Additionally in October 2020, we hedged 12,500 MMBtu/d of our 2021 Rockies gas production at nearly $3.00 per MMBtu.
In terms of immediate risks, if we were forced to shut-in a significant amount of our California production, as well as curtail some of our Utah and Colorado production, this could have a material, adverse effect on our financial and operational results. If we are forced to shut in production, we will incur additional costs to bring those associated wells back online, as well as additional costs and operating expenses while production is shut-in to, among other things, maintain the net proceedshealth of the reservoirs, meet contractual obligations and protect our interests, but without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we also need to repay borrowingsshut-in steam injection for the reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could decrease, which could result in a reduction to our borrowing base under the RBL Facility and used the remainder for general corporate purposes.

our liquidity.
In March 2018,the longer term, if depressed oil prices were to persist through 2021 and longer as currently predicted by the forward curve for oil, we may not be able to continue to generate the same level of Levered Free Cash Flow we are currently generating and our boardliquidity and capital resources may not be sufficient to conduct our business and operations in the longer term until commodity prices recover. In light of directors approvedcontinuing uncertainty, negative commodity price outlook, and significant risks mentioned above and further discussed elsewhere in this report (including under Part II, Item 1.A. “Risk Factors”), we continue to plan for a cumulative paid-in-kindprolonged downturn and our strategy to survive is focused on preserving cash, reducing costs and maintaining business continuity. We have significantly reduced our initially planned 2020 capital expenditures and non-employee operating and general and administrative expenses and we are focused on achieving additional cost reductions and improving operational efficiencies. We also temporarily suspended our quarterly cash dividend, starting with the second quarter of 2020, and year-to-date we have not repurchased any common stock under our authorized share repurchase program. As mentioned above, we enhanced our hedge positions for 2020, and to a lesser extent for 2021. Depending on the Series A Preferred Stocktiming and rate of the eventual recovery and our outlook, we may potentially use Levered Free Cash Flow to opportunistically repurchase our bonds to strengthen our balance sheet to withstand an extended low commodity price environment, to explore accretive acquisitions that would strengthen our asset base or to fund our 2021 capital expenditures in the event there is a shortfall next year. Although we continue to actively work to mitigate the evolving challenges of this severe industry downturn on our operations, our financial condition and our employees and contractors, there is no certainty that the measures we take will ultimately be sufficient. We are unable to reasonably predict when, or to what extent, commodity prices and the overall markets and global economy will stabilize, and the pace of any subsequent
48
recovery for the periods through Decemberoil and gas industry. Further, to what extent these events do ultimately impact our business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous evolving factors that cannot be predicted, including the severity and duration of the COVID-19 pandemic and future actions by OPEC+.
The RBL Facility
On July 31, 2017. The cumulative dividend was 0.050907 per share and approximately 1,825,000 shares2017, we entered into a credit agreement providing for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base (“RBL Facility”), which is further discussed in total. AlsoNote 2, Debt, in March 2018, the board approved a $0.158 per share, or approximately $5.6 million, cash dividend onNotes to the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the payments were to stockholdersCondensed Consolidated Financial Statements in Part I, Item 1 of record as of March 15, 2018. In May 2018, the board of directors approved a $0.15 per share, or approximately $5.6 million cash dividend, on the Series A Preferred Stock for the quarter endedthis report. On June 30, 2018. The payment was made to stockholders of record as of June 7, 2018.
In July,23, 2020, we completed our IPOthe regular Spring borrowing base redetermination and as a result, on July 26, 2018, our common stock began trading onentered into Limited Waiver and Amendment No. 5 to Credit Agreement (the “Amendment”), with the NASDAQ Global Select Market under the ticker symbol BRY. The Company sold 10,497,849 shares and the selling stockholders sold 2,545,630 shares at a price of $14.00 per share. We used a portion of our proceeds to repurchase 1,802,196 shares of our common stock owned by Benefit Street Partners and Oaktree Capital Management. After giving effectlenders which, among other changes to the IPO andcredit agreement described in the share repurchase,Amendment, (1) decreases the number of shares of our common stockborrowing base to $200 million; (2) decreases the elected commitment to $200 million; (3) limits the maximum borrowing availability to $150 million until the next semi-annual borrowing base redetermination which is scheduled to occur in November 2020 at which time we expect the availability to return to this elected commitment amount; (4) implements certain anti-cash hoarding provisions, including the requirement to repay outstanding increased by 8,695,653. We andloans on a weekly basis in the selling stockholders have granted the underwriters the option to purchase up to an additional 1,534,895 shares and 421,626 shares of common stock, respectively, on the same terms and conditions set forth above.
In connection with the IPO, each of the 37.7 million shares of our Series A Preferred Stock was automatically converted into 1.05 shares of our common stock or 39.6 million shares in aggregate and the right to receive a cash payment of $1.75. The cash payment was reduced in respectamount of any cash dividend paid byon the Company on suchbalance sheet (subject to certain exceptions) in excess of $30 million; (5) waives certain events of default arising from the failure to timely deliver certain hedging reports; and (6) further limits dividends and share repurchases. As of Series A Preferred Stock for any period commencing on or after April 1, 2018. BecauseSeptember 30, 2020 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, orhad no borrowings outstanding, approximately $60 million.
The Company received approximately $136$7 million in net proceeds from the offering after deducting underwriting discounts and offering expenses payable by us. We did not receive any proceeds from the sale by the selling stockholders. We used approximately $24 millionletters of the net proceeds to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the offering) from funds affiliated with Benefit Street Partners and Oaktree Capital Management.
Of the remaining approximately $112 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the $60 million we borrowed on the RBL Facility to make the payment 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. On August 20, 2018, we had approximately $388 million of available borrowing capacity under the RBL Facilitycredit outstanding, and approximately $36 million of cash on hand.
On August 21, 2018, our board of directors approved a $0.12 per share quarterly cash dividend on our common stock on a pro-rata basis from the date of our IPO through September 30, 2018 which will result in a payment of $0.09 per share.
The RBL Facility contains certain financial covenants, including the maintenance of (i) a Leverage Ratio (as defined in the RBL Facility) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the RBL Facility) not to be less than 1.00:1.00. As of June 30, 2018, our Leverage Ratio and Current Ratio were 2.63:1.00 and 3.18:1.00, respectively. As of June 30, 2018 our borrowing base was approximately $400 million and we had $327$143 million available for borrowing under the RBL Facility. At June 30, 2018, we were in compliance with the financial covenants under the RBL Facility. In connection with the issuance of the 2026 Notes, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. Borrowing base redeterminations generally become effective on, or about, each May 1 and November, 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations.
Historically,The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a Leverage Ratio of no more than 4.0 to 1.0 and (ii) a Current Ratio of at least 1.0 to 1.0. The RBL Facility also contains customary restrictions. As of September 30, 2020, our Leverage Ratio and Current Ratio were 1.5 to 1.0 and 2.7 to 1.0, respectively. In addition, the Predecessor utilized funds from debt offerings, borrowingsRBL Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under its credit facilitythe RBL Facility and net cash provided by operating activities,exercise all of their other rights and remedies, including foreclosure on all of the collateral. We were in compliance with all financial covenants under the RBL Facility as well as funding from our former parent, for capital resources and liquidity, and the primary use of capital was for the development of oil and natural gas properties.September 30, 2020.
Hedging
We have protected a significant portionsubstantially all of our anticipated cash flows throughin 2020, as well as a significant portion in 2021, using our commodity hedging program, including through fixed-price derivative contracts. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge gas purchases to protect against price increases. Our generally low-decline production base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our 2020 and 2021 hedging positions. For information regarding risks related to our hedging program, see “Item 1A. Risk Factors—Risks Related to Our Business and Industry” in our Annual Report.
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As of JuneSeptember 30, 2018,2020, we have hedgedhad the following crude oil production and gas purchases hedges.
Q4 20201H 20212H 2021
Fixed Price Oil Swaps (Brent):
  Hedged volume (MBbls)2,208 3,438 2,084 
  Weighted-average price ($/Bbl)$59.85 $45.82 $46.17 
Purchased Oil Calls Options (Brent):
Hedged volume (MBbls)276 — — 
Weighted-average price ($/Bbl)$65.00 $— $— 
Fixed Price Gas Purchase Swaps (Kern, Delivered):
  Hedged volume (MMBtu)5,060,000 9,045,000 5,535,000 
  Weighted-average price ($/MMBtu)$2.76 $2.71 $2.73 
Fixed Price Gas Purchase Swaps (SoCal Citygate):
  Hedged volume (MMBtu)155,000 — — 
  Weighted-average price ($/MMBtu)$3.80 $— $— 
In October 2020, we added 12,500 MMBtu/d of approximately 2.1 MMBbls for 2018, 3.7 MMBbls for 2019fixed price gas sales swaps at an average price of $2.96, indexed to Northwest Pipeline Rocky Mountains and 0.5 MMBbls for 2020.
Future cash flows are subject to a number of variables discussed in "Risk Factors". Further, our capital investment budgetCIG, for the year endedperiod January 1, 2021 through December 31, 2021.
The following table summarizes the historical results of our hedging activities.
Three Months EndedNine Months Ended
September 30, 2020June 30, 2020September 30, 2019September 30, 2020September 30, 2019
Crude Oil (per Bbl):
Realized sales price, before the effects of derivative settlements$39.88 $28.98 $57.92 $39.00 $58.79 
Effects of derivative settlements$16.28 $25.42 $7.31 $16.97 $4.30 
Oil with hedges ($/Bbl)$56.16 $54.40 $65.23 $55.97 $63.09 
Purchased Natural Gas (per MMBtu):
Purchase price, before the effects of derivative settlements$2.69 $1.74 $2.67 $2.25 $3.17 
Effects of derivative settlements$0.10 $1.11 $0.30 $0.60 $0.09 
Purchased Natural Gas with hedges$2.79 $2.85 $2.97 $2.85 $3.26 
Cash Dividends
Our Board of Directors approved $0.12 per share quarterly cash dividend on our common stock for the first quarter of 2020, which we paid in April 2020. In April 2020, in connection with the current low oil price environment, we temporarily suspended our quarterly dividend until oil prices recover. As of October 31, 2020, the Company has paid approximately $65 million in dividends, since the inception of its dividend program in the third quarter of 2018.
Stock Repurchase Program
In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at that time, they authorized initial repurchases of up to $50 million under the program. In February 2020, the Board of
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Directors authorized the repurchase of the remaining $50 million of our $100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not allocateobligate Berry Corp. to purchase shares during any amountsperiod or at all. Any shares acquired will be available for acquisitionsgeneral corporate purposes. The Company repurchased a total of oil5,057,682 shares under the stock repurchase program for approximately $50 million as of December 31, 2019. For the nine months ended September 30, 2020, we did not repurchase any shares under the stock repurchase program.
Bond Repurchase Program
In February 2020, our Board of Directors adopted a program to spend up to $75 million for the opportunistic repurchase of our 2026 Notes. The manner, timing and natural gas properties. If we make acquisitions, weamount of any purchases will be determined based on our evaluation of market conditions, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any bonds under the bond repurchase program.
Corporate Organization
Berry Corp., as Berry LLC’s parent company, has no independent assets or operations. Any guarantees of potential future registered debt securities by Berry Corp. or Berry LLC would be requiredfull and unconditional. Berry Corp. and Berry LLC currently do not have any other subsidiaries. In addition, there are no significant restrictions upon the ability of Berry LLC to reduce the expected level of capital investmentsdistribute funds to Berry Corp. by distribution or seek additional capital. If we require additional capital we may seek such capital through borrowingsloan other than under the RBL Facility. None of the assets of Berry Corp. or Berry LLC represent restricted net assets.
The RBL Facility joint venture partnerships, production payment financings, asset sales, additional offeringspermits Berry LLC to make distributions to Berry Corp. so long as both before and after giving pro forma effect to such distribution no default or borrowing base deficiency exists, availability equals or exceeds 20% of debtthe then effective borrowing base, and Berry Corp. demonstrates a pro forma leverage ratio less than or equity securities or other means. We cannot be sure that needed

capital would be available on acceptable terms or at all. If weequal to 2.5 to 1.0. The conditions are unable to obtain funds on acceptable terms, we may be required to curtail our current development programs, which could resultcurrently met with significant declines in our production.
See "-Capital Expenditures and Capital Budget" for a description of our 2018 capital expenditure budget.margin.
Statements of Cash Flows
The following is a comparative cash flow summary:
 Berry Corp. (Successor)Berry LLC (Predecessor)
 Six Months EndedFour Months EndedTwo Months Ended
 June 30, 2018June 30, 2017February 28, 2017
(in thousands)   
Net cash:   
  Provided by (used in) operating activities$(49,548)$44,937
$22,431
  Used in investing activities(42,347)(72,328)(3,133)
  Provided by (used in) financing activities46,467
(15,000)(162,668)
Net decrease in cash, cash equivalents and restricted cash$(45,428)$(42,391)$(143,370)
    
Nine Months Ended
September 30,
20202019
(in thousands)
Net cash:
  Provided by operating activities$144,419 $164,267 
  Used in investing activities(74,522)(176,138)
  Used in financing activities(22,277)(56,809)
Net increase (decrease) in cash and cash equivalents$47,620 $(68,680)
Operating Activities
Cash used in operating activities was approximately $50 million for the six months ended June 30, 2018 compared to cash provided by operating activities of approximately $67 milliondecreased for the sixnine months ended JuneSeptember 30, 2017, including the successor and predecessor periods. The amounts used in 2018 included $1272020 by approximately $20 million for early-terminated hedges which offset $77 million of cash provided by other operating activities. Aside from the impact of these early hedge terminations, the decrease in cash used in operating activities in the first six months of 2018when compared to 2017 reflected higherthe nine months ended September 30, 2019, due to decreased sales of $129 million, and lower costs, slightlyincreased general and administrative expenses of $6 million. These decreases were partially offset by negativeincreased derivatives settlements received of $80 million, decreased lease operating expenses and electricity generation expenses of $24 million, decreased taxes, other than income taxes of $4 million, and working capital effects.changes of $7 million.
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Investing Activities
The following provides a comparative summary of cash flowflows from investing activities:
Nine Months Ended
September 30,
20202019
(in thousands)
Capital expenditures:(1)
Development of oil and natural gas properties$(58,370)$(157,281)
Purchase of other property and equipment(3,951)(12,394)
Changes in capital investment accruals(10,347)(4,613)
Acquisition of properties and equipment and other(2,104)(2,819)
Proceeds from sale of properties and equipment and other250 969 
Cash used in investing activities$(74,522)$(176,138)
 Berry Corp.
(Successor)		Berry LLC (Predecessor)
 Six Months EndedFour Months EndedTwo Months Ended
(in thousands)June 30, 2018June 30, 2017February 28, 2017
Capital expenditures (1)$(45,369)$(32,878)$(3,158)
Proceeds from sale of properties and equipment and other3,022
—
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Deposit on acquisition of properties—
(39,450)—
Cash used in investing activities:$(42,347)$(72,328)$(3,133)
__________
(1)    basedBased on actual cash payments rather than accruals.
Cash used in investing activities was approximately $42decreased $102 million for the sixnine months ended JuneSeptember 30, 2018. The decrease in cash used for investing activities for the six months ended June 30, 20182020 when compared to the same period in 2017 including the successor and predecessor periods, was2019, primarily due to the deposit made for the acquisition of the Hill propertya decrease in 2017 offset by increased capital spending in accordance with the six months ended June 30, 2018.revised 2020 capital budget.
Financing Activities
Cash providedused by financing activities was approximately $46$22 million for the sixnine months ended JuneSeptember 30, 20182020 and wasdecreased by approximately $35 million from the nine months ended September 30, 2019. The decrease is largely due to receiving $391 million net proceeds from the issuance of our 2026 Notes offset by payments on our RBL Facility, additional net

borrowings of $313 million, the repurchase of a right to our shares of $20 million, which is reflected as treasury stock cash dividends declared on our Series A Preferred Stockpurchases of $36 million in the aggregate amount of $11 million and $9 million of debt issuance costs. For the sixnine months ended JuneSeptember 30, 2017, including2019 and none in the successor and predecessor periods,nine months ended September 30, 2020. Additionally, we paid fewer dividends in 2020 by approximately $10 million. Partially offsetting the positive cash impact of these activities, we reduced our net cash used in financing activities related to payments on our previous credit facilities ofborrowings by approximately $513$12 million offset by the receipt of proceeds from the issuance of our Series A Preferred Stock of $335 million.
Debt
2026 Notes Offering
In February 2018, we issued $400 million in aggregate principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the issuance to repay the $379 million outstanding balance on the RBL Facility in 2020 compared to 2019.
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Balance Sheet Analysis
The changes in our balance sheet from December 31, 2019 to September 30, 2020 are discussed below.
September 30, 2020December 31, 2019
(in thousands)
Cash and cash equivalents$47,620 $— 
Accounts receivable, net$48,798 $71,867 
Derivative instruments assets - current and long-term$59,669 $9,691 
Other current assets$20,318 $19,399 
Property, plant & equipment, net$1,260,755 $1,576,267 
Other non-current assets$9,297 $12,974 
Accounts payable and accrued liabilities$95,237 $151,811 
Derivative instruments liabilities - current and long-term$1,516 $4,958 
Long-term debt$393,219 $394,319 
Deferred income taxes liability - long-term$9,318 $9,057 
Asset retirement obligation - long-term$136,392 $124,019 
Other non-current liabilities$36,150 $33,586 
Equity$774,625 $972,448 
See "Liquidity and usedCapital Resources" for discussions about the remainderchanges in cash and cash equivalents.
The $23 million decrease in accounts receivable was driven mostly by lower sales, both price and volume period-over-period, partially offset by higher hedge settlements at each period-end.
The $53 million increase in derivative assets and liabilities reflected the net appreciation in the mark-to-market values of the derivatives, lower forward curve prices relative to the contract fixed price, at the end of each period presented, as well as the change in positions held at the end of each period and the settlements received and paid throughout the periods.
The $316 million decrease in property, plant and equipment was largely the result of the $289 million impairment on our oil and gas properties in the first quarter of 2020, as well as depreciation expense of $101 million, partially offset by capital investments of $61 million, $6 million of acquisitions and capitalized interest and $6 million for general corporate purposes.asset retirement obligations.
We may, at our option, redeem all or aThe $4 million decrease in other non-current assets is mainly due to deferred debt issuance cost amortization.
The $57 million decrease in accounts payable and accrued liabilities included approximately $21 million of decreased accruals and spending for various capital and operating costs due to the reduced level of these costs in 2020, $13 million fewer royalties accrued due to decreased sales, $12 million reclassified from current to long-term portion of the 2026 Notesasset retirement obligation based on budgeted spending and regulatory requirements, and the $10 million impact of dividends accrued at any time on or after February 15, 2021. We are also entitledthe end of 2019 with no corresponding accrual at September 30, 2020.
The increase in long-term deferred income taxes liability is due to redeem up to 35%the income tax expense and change in current portion due during the period.
The $12 million increase in the long-term portion of the aggregate principal amountasset retirement obligation from $124 million at December 31, 2019 to $136 million at September 30, 2020 was due to $7 million of accretion, $6 million of liabilities incurred and $12 million of reclassification from the 2026 Notes before February 15, 2021, with an amountcurrent portion due to changes in budgeted spending and regulatory requirements. These increases were partially offset by $12 million of cash not greater thanliabilities settled during the net proceeds that we raise in certain equity offerings at a redemption price equal to 107%period.
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The 2026 Notes are our senior unsecured obligationsincrease in other non-current liabilities was driven by higher greenhouse gas liabilities as a result of periodic emissions and rank equally in right ofslight price increases. This liability is due for payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The notes are fully and unconditionally guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries (othermore than Berry LLC). The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the 2026 Notes.one year from September 30, 2020.
The indenture governing the 2026 Notes contains restrictive covenants that may limit our abilitydecrease in equity of $198 million was due to among other things:net loss of $199 million and $10 million of common stock dividends declared. These decreases were partially offset by $11 million of stock-based incentive equity awards, net of taxes.
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness
transfer, sell or dispose of assets;
make investments;
create certain liens securing indebtedness;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets; and
engage in transactions with affiliates.
The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of our subsidiaries.
The RBL Facility

On July 31, 2017, Berry LLC, as borrower, entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base, and provided an initial commitment of $500 million. The RBL Facility also provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the RBL Facility on a dollar for dollar basis. Borrowing base redeterminations become effective on or about each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations. In connection with the issuance of the 2026 Notes, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. As of June 30, 2018, we had $66 million in borrowings and

approximately $7 million in letters of credit outstanding and borrowing availability of $327 million under the RBL Facility. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.
The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary London interbank offered rate plus an applicable margin ranging from 2.50% to 3.50% per annum, and (ii) a customary base rate plus an applicable margin ranging from 1.50% to 2.50% per annum, in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average daily unused amount of the borrowing availability under the RBL Facility. We have the right to prepay any borrowings under the RBL Facility with prior notice at any time without a prepayment penalty, other than customary “breakage” costs with respect to eurodollar loans.
Berry Corp. guarantees, and each future subsidiary of Berry Corp. (other than Berry LLC), with certain exceptions, is required to guarantee, our obligations and obligations of the other guarantors under the RBL Facility and under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). In addition, pursuant to a Guaranty Agreement dated as of July 31, 2017 (the “Guaranty Agreement”), Berry LLC guarantees the Guaranteed Obligations. The lenders under the RBL Facility hold a mortgage on at least 85% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions. The RBL Facility, with certain exceptions, also requires that any future subsidiaries of Berry LLC will also have to grant mortgages, security interests and equity pledges.
The RBL Facility requires us to maintain on a consolidated basis as of September 30, 2017 and each quarter-end thereafter (i) a Leverage Ratio of no more than 4.00 to 1.00 and (ii) a Current Ratio of at least 1.00 to 1.00. The RBL Facility also contains customary restrictions that may limit our ability to, among other things:
incur or guarantee additional indebtedness;
transfer, sell or dispose of assets;
make loans to others;
make investments;
merge with another entity;
make or declare dividends;
hedge future production or interest rates;
enter into transactions with affiliates;
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral.
Lawsuits, Claims, Commitments, Contingencies and Contractual ObligationsContingencies
In the normal course of business, we, or our subsidiary, are the subject of, or party to, lawsuits, environmentalpending or threatened legal proceedings, contingencies and other claims and other contingenciescommitments involving a variety of matters that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civilfines and penalties, remediation costs, or injunctive or declaratory relief.
On May 11, 2016 our predecessor entity filed the Chapter 11 Proceeding.  Our bankruptcy case was jointly administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et. al., Case No. 16-60040.  On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding.  On the Effective Date the plan became effective and was implemented.  The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims. 
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at JuneSeptember 30, 20182020 and December 31, 2017. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.2019. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.

For information related to Berry LLC’s emergence from bankruptcy and the terms of the RBL Facility, see “—Chapter 11 Bankruptcy and Our Emergence” and “Description of Other Indebtedness—The RBL Facility.”
We, or our subsidiary, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of JuneSeptember 30, 2018,2020, we are not aware of material indemnity claims pending or threatened against us.

Counterparty Credit Risk
We accounthave certain commitments under contracts, including purchase commitments for goods and services. Prior to our commodity derivatives at fair value. We had three commodity derivative counterparties at2017 emergence, Berry entered into a Carry and Earning Agreement with Encana, effective June 30, 2018 and five at7, 2006, in connection with our Piceance assets which, among other things, required us to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2017.2019, we fulfilled the obligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We did not receive collateralwill defend the matter vigorously, however, given the uncertainty of litigation and the preliminary stage of the case, among other things, at this time we cannot estimate the reasonable possible loss, if any, that may result from anythis action.
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Contractual Obligations
The following is a summary of our counterparties.commitments and contractual obligations as of September 30, 2020:
Payments Due
TotalLess Than 1 Year1-3
Years		3-5
Years		Thereafter
(in thousands)
Debt obligations:
RBL Facility$— $— $— $— $— 
2026 Notes400,000 — — — 400,000 
Interest(1)
150,529 28,000 56,000 56,000 10,529 
Other:
Asset retirement obligations(2)
150,092 13,700 — — 136,392 
Off-Balance Sheet arrangements:
Processing, transportation and storage contracts(3)
9,822 5,350 4,472 — — 
Operating lease obligations11,552 1,848 3,724 3,100 2,880 
Other purchase obligations(4)
35,100 18,000 17,100 — — 
Total contractual obligations$757,095 $66,898 $81,296 $59,100 $549,801 
__________
(1)    Represents interest on the 2026 Notes computed at 7.0% through contractual maturity in 2026.
(2)    Represents the estimated future asset retirement obligations on a discounted basis. We minimizedo not show the credit risklong-term asset retirement obligations by year as we are not able to precisely predict the timing of our derivative instruments by limiting our exposurethese amounts. Because these costs typically extend many years into the future, estimating these future costs requires management to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangementsmake estimates and judgments that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty nettingrevisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See Note 6 for additional information.
(3)    Amounts include payments which will become due under long-term agreements governing such derivativesto purchase goods and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Off-Balance Sheet Arrangements
During the six months ended June 30, 2018, there were no significant changes in our consolidated contractual obligations from those reportedservices used in the prospectus.normal course of business to secure transportation of our natural gas production to market, as well as, pipeline, processing and storage capacity.
(4)    We have certain commitments under contracts, including purchase commitments for goods and services. We previously had an obligation to a counterparty in connection with our Piceance assets to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the obligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We will defend the matter vigorously, however, given the uncertainty of litigation and the preliminary stage of the case, among other things, at this time we cannot estimate the reasonable possible loss, if any, that may result from this action. We currently have a drilling commitment in which we are required to drill 97 wells with an estimated total cost of $29 million by August 2022 and 40 of those wells are required to be drilled by July 2021.

Recently AdoptedCritical Accounting Policies and Disclosure Changes

Estimates
See Note 1, Accounting and Disclosure Changes,Basis of Presentation, in the Notes to Consolidated Condensed Financial Statements in Part I, Item 1 of this Form 10-Q.

Safe Harbor StatementCautionary Note Regarding Outlook and Forward-Looking Information

Statements
The information included or incorporated by reference in this documentQuarterly Report includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, maintenance capital requirements,for sustained production levels, expected production and costs, reserves, hedging activities, capital investmentsexpenditures, return of capital, improvement of recovery factors and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal,
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guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect us are discussed below in Part II, Item 1A. “Risk Factors” in this Quarterly Report, as well as in Part I, Item 1A. “Risk Factors” our results of operationsmost recent Annual Report on Form 10-K and financial position appear in Risk Factors inother filings with the prospectus.

Securities and Exchange Commission.
Factors (but not necessarily all the factors) that could cause results to differ include among others:

•the length, scope and severity of the ongoing COVID-19 pandemic, including the effects of related public health concerns and the impact of actions taken by governmental authorities and other third parties in response to the pandemic and its impact on commodity prices, supply and demand considerations, and storage capacity;
•global economic trends, geopolitical risks and general economic and industry conditions, such as those resulting from the COVID-19 pandemic and from the actions of foreign producers, importantly including OPEC+ and changes in OPEC+'s production levels;
•volatility of oil, natural gas and NGL prices;prices, including the sharp decline in crude oil prices that occurred in the first quarter and second quarter of 2020;
•the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;
•the California and global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources;
•supply of and demand for oil, natural gas and NGLs;
•disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations;
•inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, and meet our working capital requirements;requirements or fund planned investments;
•price fluctuations and availability of natural gas;gas and electricity and the cost of steam;
•our ability to use derivative instruments to manage commodity price risk;
impact•the regulatory environment, including availability or timing of, environmental, health and safety,conditions imposed on, obtaining and/or maintaining permits and other governmental regulations, and of current approvals, including those necessary for drilling and/or pending legislation;development projects;
uncertainties associated with estimating proved reserves and related future cash flows;
our inability to replace our reserves through exploration and development activities;
•our ability to meet our proposedplanned drilling schedule, including due to our ability to obtain permits on a timely basis or at all, and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
•uncertainties associated with estimating proved reserves and related future cash flows;
•our ability to replace our reserves through exploration and development activities;
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•drilling and production results, including lower–than–expected production, reserves or resources from development projects or higher–than–expected decline rates;
•our ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating wells;
•changes in tax laws;
•effects of competition;

•uncertainties and liabilities associated with acquired and divested assets;
•our ability to make acquisitions and successfully integrate any acquired businesses;
market fluctuations in electricity prices and the cost of steam;
asset impairments from commodity price declines;
•large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
•geographical concentration of our operations;
•the creditworthiness and performance of our ability to improve our financial results and profitability following our emergence from bankruptcy and other risks and uncertainties relatedcounterparties with respect to our emergence from bankruptcy;hedges;
changes in tax laws;
•impact of derivatives legislation affecting our ability to hedge;
•failure of risk management and ineffectiveness of internal controls;
concerns about climate change•catastrophic events, including wildfires, earthquakes and other air quality issues;pandemics;
catastrophic events;•environmental risks and liabilities under federal, state, tribal and local laws and regulations (including remedial actions);
•potential liability resulting from pending or future litigation;
•our ability to recruit and/or retain key members of our senior management and key technical employees;
•information technology failures or cyber attacks:attacks; and

•governmental actions and political conditions, as well as the actions by other third parties that are beyond our control.
WeExcept as required by law, we undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

All forward-looking statements, expressed or implied, included in this reportprospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.



Item 3. Quantitative and Qualitative Disclosures About Market Risk
For the three months ended JuneSeptember 30, 2018,2020, there were no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A)- Quantitative and Qualitative Disclosures About Market Risk, in the prospectus.2019 Annual Report, except as discussed below.
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Price Risk
Our most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues, certain costs such as fuel gas, and cash flows are likewise affected. In addition, aAdditional non-cash write-down ofimpairment charges for our oil and gas properties may be required if commodity prices experience further significant declines.
We have hedged a significant decline.large portion of our expected crude oil production and our natural gas purchase requirements to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls and puts to hedge. We do not enter into derivative contracts for speculative trading purposes and we have not accounted for our derivatives as cash-flow or fair-value hedges. We continuously consider the level of our oil production and gas purchases that is appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity prices, our expected capital and operating costs, our overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of hedging contained in any credit facility or other debt instrument applicable at the time.
We determine the fair value of our oil and natural gas derivatives using valuation techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We validate data provided by third parties by understanding the valuation inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. At JuneSeptember 30, 2018,2020, the fair value of our hedge positions was a net liabilityasset of approximately $15 million, as determined from prices provided by external sources that are not actively quoted.$58 million. A 10% increase in the oil and natural gas index prices above the JuneSeptember 30, 20182020 prices would result in a net liability of approximately $57 million, which represents a decrease in the fair value ofnet asset to approximately $42 million; conversely, a 10% decrease in the oil and natural gas index prices below the JuneSeptember 30, 20182020 prices would result in a net liability of approximately $4 million, which represents an increase in the fair value ofnet asset to approximately $11$99 million. For additional information about derivative activity, see Note 4.3, Derivatives, in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report.
Counterparty Actual gains or losses recognized related to our derivative contracts depend exclusively on the price of the underlying commodities on the specified settlement dates provided by the derivative contracts.
Credit Risk
We had three commodityOur credit risk relates primarily to trade receivables and derivative counterparties at June 30, 2018, which were all liability positions. We did not receive collateral from anyfinancial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For derivative instruments entered into as part of our counterparties. We minimize the credit risk of our derivative instruments by limiting our exposure to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangements that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivativesprogram, we are subject to counterparty netting under agreements governing such derivativescredit risk to the extent the counterparty is unable to meet its settlement commitments. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and thereforecontinue to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.
As of September 30, 2020, the substantial majority of the credit exposure related to our derivative financial instruments was with investment grade counterparties. We believe exposure to credit-related losses at September 30, 2020 was not material and actual losses associated with credit risk of loss due to counterparty nonperformance is somewhat mitigated.


have not been material for all periods presented.
Interest Rate Risk
Our RBL Facility has a variable interest rate on outstanding balances. As of JuneSeptember 30, 2018, there were $66 million outstanding2020, we had no borrowings under our RBL Facility which incurredand thus the interest at floating rates. See Note 3 for additional information regarding interest rates on outstanding debt. As of June 30, 2018, a 1% increase in the respective market rate would result in an estimated $0.7 million increase in annual interest expense.risk exposure is not material. The 2026 Notes have a fixed interest rate and thus we are not exposed to interest rate risk on these.these instruments. See Note 2, Debt, in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report for additional information regarding interest rates on our outstanding debt.
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Item 4. Controls and Procedures
Our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officerthey each concluded that our disclosure controls and procedures were effective as of JuneSeptember 30, 2018.2020.
There were no changes in the Company’s internal control over financial reporting during the third quarter of 2020 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II – Other Information


Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 54 to the condensed consolidated financial statements in Part I of this Form 10-Q and Note 75 to our consolidated financial statements for the year ended December 31, 20172019 included in the prospectus.Annual Report.


Item 1A. Risk Factors
WeIn addition to factors noted in our most recent Annual Report, additional factors that may impact our financial and operational results, include the following:
Attempts by several states to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels within the state.
Recently, California and Colorado, have taken several actions that could adversely impact oil and gas production in those states. On September 23, 2020, Governor Gavin Newsom of California issued an executive order (the "Order") that seeks to reduce both the supply of and demand for fossil fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: phasing out the sale of emissions-producing vehicles; developing strategies for the closure and repurposing of oil & gas facilities in California; and ending the issuance of new hydraulic fracturing permits in the state by 2024. The Order also directs CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations, which may include setbacks, to address these concerns by December 31, 2020. Any of these developments may adversely impact both demand for our products or production from our properties.
While the Order does not impose a ban on the issuance of hydraulic fracturing permits, Governor Newsom has announced plans to ask the legislature to pass legislation to this effect. While several California legislators have already indicated that they intend to propose such a ban, the ultimate outcome of any proposed legislation remains uncertain at this time, as past measures to further impose additional stringent requirements upon oil and gas activities in the California legislature were not successful. For example, in both 2019 and 2020, California considered legislation to impose a statewide setback distance between certain oil and natural gas operations and residences, schools, and healthcare facilities. However, in both cases, the proposal failed to receive the approval of the California State Senate.
Separately, in September 2020, the Colorado Oil and Gas Conservation Commission (“COGCC”) announced that it will consider imposing a 2,000-foot setback requirement for drilling and fracking operations statewide, allowing for variances subject to certain conditions. The vote on this rulemaking is expected to take place at the COGCC’s November 6, 2020 meeting. While we cannot predict the final outcome of the COGCC’s actions, any regulation restricting the siting of oil and gas facilities or otherwise imposing more stringent operating controls may adversely impact production from our properties.
The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our operations and financial condition will depend on future developments, which are highly uncertain and cannot be predicted.
In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19. This pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. This resulted in a significant reduction in demand for and prices of crude oil, natural gas and NGL, which was compounded by the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire on August 1, 2020.
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In mid-April 2020, members of OPEC+ agreed to certain production cuts; however, these cuts only slightly offset the significant decrease in demand resulting from the COVID-19 pandemic and related economic repercussions. During the second quarter of 2020, the price of Brent crude oil reached historic low of just under $20 per barrel. Although pricing has strengthened slightly, it is still lower than pre-pandemic levels and the current futures forward curve for Brent crude indicates that prices are expected to continue at low levels for an extended time. As of November 1, 2020, the benchmark Brent oil price was $37.46 per barrel as compared to the average benchmark Brent oil price of $63.15 per barrel used to determine our 2019 year end reserves based on SEC pricing.
Additionally, although the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. During the second quarter of 2020, we experienced an adverse widening in the price differential between Brent and California crude due to the lack of local demand and storage capacity. This differential widening improved in the third quarter 2020 as the market storage concerns began to soften, however, if California pricing remains weak, or declines, our financial and operating results will be adversely affected.
If the reduced demand for, and prices of, crude oil and NGLs continue for a prolonged period, our operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected. At the end of March 2020, the Company reduced its planned capital expenditures by more than 50%, which negatively impacted production during the second and third quarters 2020 and may negatively impact future production levels due to the natural production decline of our assets. This, combined with expected lower commodity prices, could materially adversely affect our cash flows and the quantity and value of estimated proved reserves that may be attributed to our properties. A persistent price decline could adversely affect the economics of our existing wells and planned future wells, result in additional impairment charges to existing properties and cause us to delay or abandon planned drilling operations as uneconomical.
Our operations also may be adversely affected if significant portions of our workforce - and that of our customers and suppliers - are unable to work effectively, including because of illness, quarantines, government actions, or other restrictions in connection with the pandemic. Over the later part of March, we implemented workplace restrictions in response to developing government directives and we are continuing to monitor national, state and local government directives where we have operations and/or offices. For several months, most of our personnel worked remotely and many of our key vendors, service suppliers and partners have been as well. Although we managed the transition to temporary work from home arrangements and subsequent office re-openings without a significant loss in business continuity, we incurred additional costs and experienced some inefficiencies during the second and third quarters 2020 as a result. If the ongoing outbreak were to worsen, and additional restrictions be implemented, we may again have to consider remote work arrangements, and certain operational and other business processes could slow which may result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies, any of which could adversely affect our operating results for as long as the current pandemic persists and potentially for some time after the pandemic subsides.
The extent to which the COVID-19 pandemic adversely affects our business, results of operations, and financial condition will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by governmental authorities and other third parties in response to the pandemic.
Our ability to operate profitably and our financial condition are highly dependent on energy prices. The outbreak of COVID-19 followed by certain actions taken by OPEC+ caused crude oil prices to decline significantly beginning in the first quarter of 2020 and prices have remained weak and below pre-pandemic levels. If oil prices continue to decline or remain at current levels for a prolonged period, our business, financial condition and results of operations may be materially and adversely affected.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to various risks
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wide fluctuations in response to relatively minor changes in supply and uncertaintiesdemand. Historically, the markets for oil and natural gas have been extremely volatile and these markets will likely continue to be volatile in the coursefuture. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
•changes in global supply and demand for oil and natural gas, including changes in demand resulting from general and specific economic conditions relating to the business cycle and other factors (e.g., global health epidemics such as the recent COVID-19 pandemic);
•the actions of OPEC / OPEC+;
•the price and quantity of imports of foreign oil and natural gas;
•political conditions, including embargoes, in or affecting other oil-producing activity;
•the level of global oil and natural gas exploration and production activity
•the level of global oil and natural gas inventories;
•weather conditions;
•technological advances affecting energy consumption; and
•the price and availability of alternative fuels.
Global economic growth drives demand for energy from all sources, including fossil fuels. Historically, when the U.S. and global economies experience weakness, demand for energy has declined. Similarly, should growth in global energy production outstrip demand, excess supplies may arise. Declines in demand and excess supplies may result in accompanying declines in commodity prices and deterioration of our business. A discussionfinancial position along with our ability to operate profitably and our ability to obtain financing to support operations.
In the first quarter of 2020, crude oil prices fell sharply and dramatically, due in part to significantly decreased demand as a result of the COVID-19 pandemic coupled with the increase in supply from the actions of OPEC+. On June 6, 2020, members of OPEC+ agreed to certain production cuts, which slightly offset the decrease in demand resulting from the COVID-19 pandemic. In August 2020, these production cuts were eased slightly and the current output reduction levels are expected to remain through the end of the year.
During the second and third quarters 2020, oil prices recovered slightly from the historical low levels at the beginning of the second quarter as global demand began to increase gradually with containment of the COVID-19 outbreak in areas around the globe and the supply surge was curtailed as members of OPEC+ agreed to certain production cuts. This recovery appears fragile and has flattened, with oil price volatility remaining elevated and oil demand remaining below pre-COVID-19 pandemic levels. Demand, and pricing, may again decline due to the ongoing COVID-19 pandemic, particularly if there is a resurgence of the outbreak during the latter part of the year as some are predicting, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time. If storage availability also becomes further constrained, Brent and/or California oil prices may go materially lower and could potentially even become negative as WTI oil prices did on April 20, 2020. If crude oil prices continue to decline or remain at current levels for a prolonged period, our operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected.
Additionally, although the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. Even as Brent pricing fell during the second quarter 2020, we experienced an adverse widening in the price differential between Brent and the California benchmark due to the lack of local demand and storage capacity. Although market conditions improved and the differential widening softened toward the end of the second quarter 2020, if California pricing remains weak, or declines, our financial and operating results will be adversely affected.
Past declines in prices reduced, and any declines that may occur in the future can be expected to reduce, our revenues and profitability as well as the value of our reserves. Such declines adversely affect well and reserve economics and may reduce the amount of oil and natural gas that we can produce economically, resulting in deferral or cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve
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sufficiently to support such operations. Any extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
The marketability of our production is dependent upon transportation and storage facilities and other facilities, most of which we do not control, and the availability of such riskstransportation and uncertaintiesstorage capabilities, which have been severely limited by recent market conditions related to the COVID-19 pandemic and the current oversupply of oil and natural gas. If additional facilities do not become available, or, even if such facilities are available, but we are unable to access such facilities on commercially reasonable terms, our operations will likely be interrupted, our production could be curtailed, and our revenues reduced, among other consequences.
The marketing of oil, natural gas and NGLs production depends in large part on the availability, proximity and capacity of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. Because of the significantly reduced demand for oil and natural gas as a result of the COVID-19 pandemic and the current oversupply of oil and natural gas in the market, available storage and transportation capacity for our production is limited and may become completely unavailable in the near future. Storage became scarce during the second quarter of 2020 due to the unprecedented dual impact of a severe global oil demand decline coupled with a substantial increase in supply. As traditional tanks filled, large quantities of oil were being stored in offshore tankers around the world, including off the coast of California. Where storage was available, such as offshore tankers, storage costs increased sharply. If the imbalance between supply and demand and the related shortage of storage capacity worsen, the prices we receive for our production could deteriorate and could potentially even become negative as WTI oil prices did on April 20, 2020.
During the second quarter of 2020, we obtained additional storage capacity to support our planned production for the remainder of the year and into 2021. As market conditions improved, we released a portion of the capacity. However, the risk remains that storage for oil may be foundunavailable and our existing capacity may be insufficient to support planned production rates in the event of demand for our oil deteriorating again or a supply surge or both. If we are unable to obtain additional storage capacity if needed, we could be forced to shut-in a significant amount of our California production, as well as curtail some of our Utah and Colorado production, which could have a material, adverse effect on our financial condition, liquidity and operational results. Whether and when we will have to reduce or shut-in production, and the extent and duration to which we may have to do so, cannot be reasonably predicted at this time. If we are forced to shut in production, we will incur additional costs to bring the associated wells back online. While production is shut in, we will likely incur additional costs and operating expenses to, among other things, maintain the health of the reservoirs, meet contractual obligations and protect our interests, but without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we have also shut-in steam injection for the associated reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could be decreased and there could be potential additional impairments and associated charges to our earnings. A reduction in our reserves could also result in a reduction to our borrowing base under the heading Risk FactorsRBL Facility and our liquidity. The ultimate significance of the impact of any production disruptions, including the extent of the adverse impact on our financial and operational results, will be dictated by the length of time that such disruptions continue which will, in turn, depend on the how long storage remains filled and unavailable to us, which is largely based on the lack of demand for our products due to the impact of the COVID-19 impact, the duration of which is currently unknowable.
In addition to the constraints we face due to storage capacity shortages, the volume of oil and natural gas that we can produce is subject to limitations resulting from pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, and physical damage to the gathering, transportation, storage, processing, fractionation, refining or export facilities that we utilize. The curtailments arising from these and similar circumstances may last from a few days to several months or longer and, in many cases, we may be provided only limited, if any, advance notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or any inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.
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We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our net income and cash flows.
We currently have substantial U.S. federal and state net operating loss (“NOL”) carryforwards and U.S. federal general business credits (subject to change each quarter; as of December 31, 2019 estimated U.S. federal and state NOL carryforwards of approximately $122 million and $42 million, respectively, and U.S. federal general business credits of approximately $48 million). Our ability to use these tax attributes to reduce our future U.S. federal and state income tax obligations depends on many factors, including our future taxable income, which cannot be assured. In addition, our ability to use NOL carryforwards and other tax attributes may be subject to significant limitations under Section 382 and Section 383 of the Internal Revenue Code of 1986, as amended (the “Code”). Under those sections of the Code, if a corporation undergoes an “ownership change” (as defined in Section 382 of the Code), the corporation’s ability to use its pre-change NOL carryforwards and other tax attributes may be substantially limited.
Determining the limitations under Section 382 of the Code is technical and highly complex. A corporation generally will experience an ownership change if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. We may in the prospectus.future undergo an ownership change under Section 382 of the Code. If an ownership change occurs, our ability to use our NOL carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations may be materially limited, which could adversely affect our net income and cash flows.
The payment of dividends will be at the discretion of our Board of Directors.
While we have regularly declared a quarterly dividend since our July 2018 IPO, including a dividend of $0.12 per share for the first quarter of 2020, the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deems relevant. Additionally, covenants contained in our RBL Facility and the indentures governing our 2026 Notes could limit the payment of dividends. In April 2020, in response to the unprecedented impact on our business from the significant decline in oil prices and the COVID-19 pandemic, we temporarily suspended our quarterly dividend until oil prices recover. We are under no obligation to make dividend payments on our common stock and cannot be certain when such payments may resume in the future.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities
DuringStock Repurchase Program
In December 2018, our Board of Directors adopted a program for the quarter ended June 30, 2018, we issued 190,260 RSUs and 117,088 PRSUsopportunistic repurchase of up to certain$100 million of our employeescommon stock. Based on the Board’s evaluation of market conditions for our common stock at that time, they authorized initial repurchases of up to $50 million under the program. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million of our $100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and directors in connectionamount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with services providedoutstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to us by such persons. As of August 21, 2018, 681,092 RSUs and 749,833 PRSUs remain outstanding. We also granted 1,566purchase shares of restricted stock to employees in connection with services provided to us by such persons.during any period or at all. Any shares acquired will be available for general corporate purposes.
The offers, sales and issuancesCompany repurchased a total of the securities described in the preceding paragraph were deemed to be exempt from registration either under Rule 701 promulgated5,057,682 shares under the Securities Act in that the transactions were under compensatory benefit plans and contracts relating to compensation, or under Section 4(a)(2) of the Securities Act in that the transactions were between an issuer and members of its senior executive management and did not involve any public offering within the meaning of Section 4(a)(2).

Use of Proceeds
On July 30, 2018, we completed our IPO of common stock pursuant to our registration statement on Form S-1 (File 333-226011), as amended and declared effective by the SEC on July 25, 2018. Goldman Sachs & Co. LLC, Wells Fargo Securities, LLC and BMO Capital Markets Corp. served as representatives of the several underwritersrepurchase program for the IPO. The offering did not terminate before all of the shares in the IPO that were registered in the registration statement were sold. Upon completion of the IPO, we and the selling stockholders sold 13,043,479 shares at a price to the public of $14.00 per share, raising approximately $183 million of gross proceeds, with gross proceeds to Berry of approximately $147 million and gross proceeds to the selling stockholders of approximately $36 million. Of the 13,043,479 shares sold to the public, 10,497,849 shares were issued and sold by us, and 2,545,630 shares were sold by the selling stockholders named in the prospectus. We incurred expenses in connection with the IPO of approximately $2.6$50 million as of JulyDecember 31, 2019. For the nine months ended September 30, 2018. After subtracting underwriting discounts and commissions of approximately $8.8 million and offering expenses, Berry received net proceeds of approximately $136 million. None of the expenses associated with our IPO were paid to directors, officers or persons owning ten percent or

more of our common stock or to their associates, or to our affiliates. We2020, we did not receiverepurchase any proceeds fromshares under the salestock repurchase program.
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Table of the shares by the selling stockholders. We and the selling stockholders granted the underwriters a 30-day option to purchase up to an additional 1,534,895 shares and 421,626 shares, respectively, of common stock at the IPO price, less underwriting discounts and commissions. We intend to use a portion of the proceeds we receive from any sale of any such option shares to purchase up to an additional 230,548 shares of common stock owned by Benefit Street.Contents

We used approximately $24 million of the net proceeds from the IPO to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the IPO) from funds affiliated with Benefit Street Partners and Oaktree Capital Management, each of which owned more than ten percent of our common stock prior to the IPO and repurchase. Of the remaining approximately $112 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the amounts we borrowed on the RBL Facility to make the payment to the holders of our Series A Preferred Stock in connection with the conversion of the Series A Preferred Stock to common stock. We used the remainder for working capital.


Item 5. Other Disclosures

Amended and Restated Employment Agreements with Arthur T. Smith, Cary D. Baetz and Gary A. Grove
On August 22, 2018, Berry LLC, a wholly-owned subsidiary of the Company, entered into amended and restated employment agreements with its Chief Executive Officer, Arthur T. “Trem” Smith (the “Smith Agreement”), its Chief Financial Officer, Cary D. Baetz (the “Baetz Agreement”) and its Chief Operating Officer, Gary A. Grove (the “Grove Agreement” and, together with the Smith Agreement and the Baetz Agreement, the “Amended Agreements”), in each case, to replace the executive’s previous employment agreement with the Company (each, a “Prior Agreement”). The Amended Agreements became effective as of August 22, 2018.
Each Amended Agreement modifies certain terms of the corresponding Prior Agreement, including the following:
Each executive is eligible to receive an annual equity award, as determined by the board of directors of the Company or a committee thereof.
Upon a termination of each executive’s employment under certain circumstances, the executive is eligible to receive (a) any earned but unpaid annual bonus for the year prior to the year of termination, (b) a prorated annual bonus for the year of termination and (c) severance in an amount equal to 18 months’ worth, for Mr. Smith, and 12 months’ worth, for Messrs. Baetz and Grove (or, following a Qualifying Termination (as defined in the applicable Amended Agreement), 24 months’ worth for Mr. Smith and 18 months’ worth for Messrs. Baetz and Grove) of the sum of the applicable executive’s base salary and target annual bonus, and reimbursement of up to an equivalent number of months’ worth of health insurance premiums.
Modifies the definition of Good Reason in certain respects.
With respect to the Smith Agreement, Mr. Smith is eligible to receive an annual bonus in a target amount equal to 100% of his then-current base salary.

All other material terms contained in the Prior Agreements remain substantially unchanged in the Amended Agreements. Copies of the Smith Agreement, Baetz Agreement and Grove Agreement are attached hereto as Exhibits 10.14, 10.15 and 10.16, respectively, and are incorporated herein by reference. The description of the material changes to the Prior Agreements contained herein is qualified in its entirety by reference to the full text of the Amended Agreements.




Item 6.    Exhibits
Exhibit NumberDescription
3.1
Exhibit NumberDescription
3.1
Second Amended and Restated Certificate of Incorporation of Berry Petroleum Corporation (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement onof Form S-1 (File No. 333-226011)8-K filed February 19, 2020)
3.2
CertificateThird Amended and Restated Bylaws of Amendment of Certificate of IncorporationBerry Corporation (bry) (incorporated by reference to Exhibit 3.2 of Form 8-K filed July 30, 2018)February 19, 2020)
3.3
Certificate of Designation of Series A Convertible Preferred Stock of Berry Petroleum Corporation (incorporated by reference to Exhibit 3.4 to the Company'sCompany’s Registration Statement on Form S-1 (File No. 333-226011))
3.4
Certificate of Amendment to Certificate of Designation (incorporated by reference to Exhibit 3.1 of Form 8-K filed July 30, 2018)
3.510.1
10.1
Amended and Restated Stockholders Agreement between Berry Petroleum CorporationCompany, LLC and certain holders party thereto (incorporatedFernandez Araujo, effective August 14, 2020 (incorporated by reference to Exhibit 10.1 of Form 8-K filed July 30, 2018)August 20, 2020)
10.2
Amended and Restated Registration Rights Agreement, dated June 28, 2018, among Berry Petroleum Corporation and the holder party thereto (incorporated by reference to Exhibit 10.4 of S-1 Registration Statement No. 333-226011)
10.3
Executive Employment Agreement, dated June 28, 2017 between Berry Petroleum Company, LLC and Cary D. Baetz (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.4
Executive Employment Agreement, dated June 28, 2017 between Berry Petroleum Company, LLC and Gary A. Grove (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.5
Second Amended and Restated Berry Petroleum Corporation 2017 Omnibus Incentive Plan, dated June 27, 2018 (incorporated by reference to Exhibit 4.3 of S-8 Registration Statement (File No. 333-226582)
10.6
Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Employees other than Executive Vice Presidents (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.7
Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Executive Vice Presidents (incorporated by reference to Exhibit 10.10 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.8
Berry Petroleum Corporation Form of Director Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.9
Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement for Employees other than Executive Vice Presidents (incorporated by reference to Exhibit 10.12 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.10
Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement for Executive Vice Presidents (incorporated by reference to Exhibit 10.13 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.11
Second Amended and Restated Berry Petroleum Corporation 2017 Omnibus Incentive Plan, dated June 27, 2018 (incorporated by reference to Exhibit 10.12 to the Company's Registration Statement on Form S-1 (File No. 333-226011)
10.12
Stock Purchase Agreement by and between Berry Petroleum Corporation, Oaktree Value Opportunities Fund Holdings, L.P. and Oaktree Opportunities X Fund Holdings (Delaware), L.P. dated July 17, 2018 (incorporated by reference to Exhibit 10.2 of Form 8-K filed July 30, 2018)
10.13
Stock Purchase Agreement by and between Berry Petroleum Corporation and certain funds affiliated with Benefit Street Partners named in Schedule I thereto, dated July 17, 2018 (incorporated by reference to Exhibit 10.3 of Form 8-K filed July 30, 2018)
10.14*
Amended and Restated Employment Agreement, Arthur T. Smith
10.15*
Amended and Restated Employment Agreement, Cary D. Baetz

31.1*
10.16*
Amended and Restated Employment Agreement, Gary A. Grove
31.1*
Section 302 Certification of Chief Executive Officer
31.2*
Section 302 Certification of Chief Financial Officer
32.1**
Section 906 Certification of Chief Executive Officer and Chief Financial Officer
101.INS*Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
101.SCH*Inline XBRL Taxonomy Extension Schema Document
101.CAL*Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*Inline XBRL Taxonomy Extension Label Linkbase Data Document
101.PRE*Inline XBRL Taxonomy Extension Presentation Linkbase Document
*Filed herewith.
**Furnished herewith.

__________
*    Filed herewith.
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GLOSSARY OF OIL AND NATURAL GASCOMMONLY USED TERMS
The following are abbreviations and definitions of certain terms that may be used in this report, which are commonly used in the oil and natural gas industry:
“Absolute TSR”means absolute total stockholder return.
“AROs”means asset retirement obligations.
“Adjusted EBITDA” is a non-GAAP financial measure defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization; 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 gains and losses on sale of assets, restructuring costs and reorganization items.
“Adjusted G&A” or “Adjusted General and Administrative Expenses” is a non-GAAP financial measure defined as general and administrative expenses adjusted for restructuring and other non-recurring costs and non-cash stock compensation expense.
“Adjusted Net Income (Loss)” is a non-GAAP financial measure defined 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.
“API” gravity means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity scale developed by the American Petroleum Institute.
“basin” means a large area with a relatively thick accumulation of sedimentary rocks.
“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.
“BLM” means for the U.S. Bureau of Land Management.
“Boe” means barrel of oil equivalent, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.
“Boe/d” means Boe per day.
“Break even” means the Brent price at which we expect to generate positive Levered Free Cash Flow.
“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.
“Btu” means one British thermal unit-aunit—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
“CAA” is an abbreviation for the Clean Air Act, which governs air emissions.
“CalGEM” is an abbreviation for the California Geologic Energy Management Division.
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“Cap-and-trade” is a statewide program in California established by the Global Warming Solutions Act of 2006 which outlined an enforceable compliance obligation beginning with 2013 GHG emissions and currently extended through 2030.
“CARB” is an abbreviation for the California Air Resources Board.
“CCA” or “CCAs” is an abbreviation for California carbon allowances.
“CERCLA” is an abbreviation for the Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous substances have been released into the environment (commonly known as “Superfund”).
“Clean Water Rule” refers to the rule issued in August 2015 by the EPA and U.S. Army Corps of Engineers which expanded the scope of the federal jurisdiction over wetlands and other types of waters.
“COGCC” is an abbreviation for the Colorado Oil and Gas Conservation Commission.
“Completion” means the installation of permanent equipment for the production of oil or natural gas.
“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“CPUC” is an abbreviation for the California Public Utilities Commission.
“CWA” is an abbreviation for the Clean Water Act, which governs discharges to and excavations within the waters of the United States.
“DD&A” means depreciation, depletion & amortization.
“Development drilling”or “Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.
“Diatomite” means a sedimentary rock composed primarily of siliceous, diatom shells.
“Differential” means an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.
"EH&S" is an abbreviation for Environmental, Health & Safety.
“Enhanced oil recovery” means a technique for increasing the amount of oil that can be extracted from a field.
“EOR” means enhanced oil recovery.
“Estimated ultimate recoveryEPA” or is an abbreviation for the United States Environmental Protection Agency.
“EUREPS” meansis an abbreviation for earnings per share.
“ESA” is an abbreviation for the sum of reserves remaining as of a given date and cumulative production as of that date. EUR is shown on a combined basis for oil and natural gas.federal Endangered Species Act.
“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.
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“FASB” is an abbreviation for the Financial Accounting Standards Board.
“FERC” is an abbreviation for the Federal Energy Regulatory Commission.
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
“FIP” is an abbreviation for Federal Implementation Plan.
“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.
“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.

“GAAP” is an abbreviation for U.S. generally accepted accounting principles.
“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
“Gross AcresGHG” or “GHGs” is an abbreviation for greenhouse gases.
“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working interest.
“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.
“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.
“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability.
“Horizontal drilling” means a wellbore that is drilled laterally.
“ICE” means Intercontinental Exchange.
“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.
“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.
“IOR” means improved oil recovery.
“IPO”is an abbreviation for initial public offering.
“LCFS” is an abbreviation for low carbon fuel standard.
“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.
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“Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less interest expense, dividends and capital expenditures.
“LIBOR” is an abbreviation for London Interbank Offered Rate.
“MBbl” means one thousand barrels of oil, condensate or NGLs.
“MBbl/d” means MBbl per day.
“MBoe” means one thousand barrels of oil equivalent.
“MBoe/d” means MBoe per day.
“Mcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.
“MMBbl” means one million barrels of oil, condensate or NGLs.
“MMBoe” means one million barrels of oil equivalent.
“MMBtu” means one million Btus.
“MMBtu/d” means MMBtu per day.
“MMcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.
“MMcf/d” means MMcf per day.
“MTBA” is an abbreviation for Migratory Bird Treaty Act.
“MW” means megawatt.
“MWHs”means megawatt hours.
“NAAQS” is an abbreviation for the National Ambient Air Quality Standard.
“NASDAQ” means Nasdaq Global Select Market.
“NEPA” is an abbreviation for the National Environmental Policy Act, which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands.
“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.
“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
“NGA” is an abbreviation for the Natural Gas Act.
“NGL” or “NGLs” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
“NRI” is an abbreviation for net revenue interest.
“NYMEX” means New York Mercantile Exchange.
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“Oil” means crude oil or condensate.

“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.
“OSHA” is an abbreviation for the Occupational Safety and Health Act of 1970.
“OTC”means over-the-counter
“PALs” is an abbreviation for project approval letters.
“PCAOB” is an abbreviation for the Public Company Accounting Oversight Board.
“PDNP” is an abbreviation for proved developed non-producing.
“PDP” is an abbreviation for proved developed producing.
“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.
“PHMSA” is an abbreviation for the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.
“Play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations.
“Porosity” means the total pore volume per unit volume of rock.
“PPA” is an abbreviation for power purchase agreement.
“Production costs” means costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.
“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.
“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing equipment and operating methods.
“Proved reserves” means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“PSUs” means performance-based restricted stock units
“PURPA” is an abbreviation for the Public Utility Regulatory Policies Act.
“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. While this measure does not include the effect of income

taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.
“QF” means qualifying facility.
“RCRA” is an abbreviation for the Resource Conservation and Recovery Act, which governs the management of solid waste.
“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.
“Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.
“Relative TSR” means relative total stockholder return.
“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
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“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.
“RSUs” is an abbreviation for restricted stock units.
“SARs” is an abbreviation for stock appreciation rights.
“SDWA” is an abbreviation for the Safe Drinking Water Act, which governs the underground injection and disposal of wastewater;.
“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.
“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.
“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“SPCC plans” means spill prevention, control and countermeasure plans.
“Steamflood” means cyclic or continuous steam injection.
“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Stimulating” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.
“Strip Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules with the exception of pricing that is based on average annual forward-month ICE (Brent) oil and NYMEX Henry Hub natural gas contract pricing in effect on a given date to reflect the market expectations as of that date.
“Superfund” is a commonly known term for CERLA.
“UIC” is an abbreviation for the Underground Injection Control program.
“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

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“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Unproved reserves” means reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
“Wellbore” means the hole drilled by the bit that is equipped for natural gasresource production on a completed well. Also called well or borehole.
“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.
“Workover” means maintenance on a producing well to restore or increase production.
“WST” is an abbreviation for well stimulation treatment.
“WTI” means West Texas Intermediate.

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SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


Berry Corporation (bry)
BERRY PETROLEUM CORPORATION(Registrant)
(Registrant)
Date:November 4, 2020
/s/ Cary Baetz
Date: August 23, 2018/s/ Michael S. HelmCary Baetz
Michael S. Helm
Chief Accounting Officer
(Duly Authorized Officer and Principal Accounting Officer)
Date: August 23, 2018/s/ Cary Baetz
Cary Baetz
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date:November 4, 2020
/s/ M. S. Helm
Michael S. Helm
Chief Accounting Officer
(Principal Accounting Officer)



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