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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2020
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 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)
16000 Dallas Parkway, Suite 500
Dallas, Texas 75248
(661616-3900
(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 ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒    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,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ Accelerated filer ☐ 
Non-accelerated filer ☒
 
Smaller reporting company 
Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes     No ☒

Shares of common stock outstanding as of October 31, 2020          79,929,335



Table of Contents
  Page
Item 1. 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
   
 
Item 1.
Item 1A.
Item 2.
Item 6.
 

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 CORPORATION (bry)
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, 2020December 31, 2019
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents$47,620 $ 
Accounts receivable, net of allowance for doubtful accounts of $2,215 at September 30, 2020 and $1,103 at December 31, 2019
48,798 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 properties 1,388,544 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 CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF 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 properties  289,085  
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, net (170) (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 

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

Table of Contents
BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)


Nine-Month Period Ended September 30, 2019
Common StockAdditional Paid-in CapitalTreasury StockRetained Earnings Total 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 —  
Common stock issued to settle unsecured claims3 (3)— —  
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, 2019
85 897,322 (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 February 2019 with no shares issued.

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, 2020
85 904,072 (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, 2020
85 908,662 (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  
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 receivable 21,985 (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 stock (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:
Beginning 68,680 
Ending$47,620 $ 


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—Basis of Presentation
“Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation, which is the sole member of Berry Petroleum Company, LLC ("Berry LLC").
As the context may require, the “Company”, “we”, “our” or similar words refer to (i) Berry Corp. and Berry LLC, its consolidated subsidiary, as a whole or (ii) either Berry Corp. or Berry LLC.
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 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 (the “U.S.”), in California (in the San Joaquin and Ventura basins), Utah (in the Uinta basin), and Colorado (in the Piceance basin).
Principles of Consolidation and Reporting
The condensed consolidated financial statements were prepared in conformity with U.S. generally accepted accounting principles (“GAAP”), which requires management to make estimates and assumptions that affect the amounts reported in the 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. We eliminated all significant intercompany transactions and balances 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.
We prepared this report pursuant to the rules and regulations of the U.S. Security and Exchange Commission (“SEC”) applicable to interim financial information, which permit the omission of certain disclosures to the extent they have not changed materially since the latest annual financial statements. We believe our disclosures are adequate to make the disclosed 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 Form 10-Q should be read in conjunction with the consolidated financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2019.
Reclassification
We reclassified certain prior year amounts in the cash flow statements to conform to the current year presentation. These reclassifications had no material impact on the financial statements.
New Accounting Standards Issued, But Not Yet Adopted
In February 2016, the Financial 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. During the second quarter of 2020, this adoption date was further delayed by FASB until fiscal years beginning after December 15, 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 increase other assets and other liabilities on our balance sheet and we are currently evaluating the impact on our consolidated results of operations.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
In December 2019, the FASB issued rules which simplify the accounting for income taxes. 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 for fiscal years beginning after December 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 FASB 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.
Note 2—Debt
The following table summarizes our outstanding debt:
September 30,
2020
December 31, 2019Interest RateMaturitySecurity
(in thousands)
RBL Facility$ $1,850 
variable rates
4.0% (2020) and 5.5% (2019), respectively
July 29, 2022
Mortgage 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 
Deferred Financing Costs
We incurred legal and bank fees related to the issuance of debt. At September 30, 2020 and December 31, 2019, debt issuance costs for the RBL Facility (as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $8 million and $11 million net of amortization, respectively. At September 30, 2020 and December 31, 2019, debt issuance costs, net of amortization, for the unsecured notes due February 2026 (the “2026 Notes”) reported in Long-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 for 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 Notes was approximately $314 million and $376 million at September 30, 2020 and December 31, 2019, respectively.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The RBL Facility
On July 31, 2017, we entered into a credit agreement that provided for a revolving loan with up to $1.5 billion of commitment, subject to a reserve borrowing base (“RBL Facility”). In June 2020, we completed our scheduled semi-annual borrowing base redetermination under our RBL Facility, which resulted in a decrease to the borrowing base to $200 million from $500 million; decrease to the elected commitments to $200 million from $400 million; limitation on the maximum borrowing availability under the RBL Facility to $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 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.
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.
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 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 September 30, 2020.
As of September 30, 2020, we had no borrowings outstanding, $7 million in letters of credit outstanding, and approximately $143 million of available borrowings capacity under the RBL Facility.
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 amount 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 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 addition, there are no significant restrictions upon the ability of Berry 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 after giving pro forma effect to such distribution no default or borrowing base deficiency exists, availability equals or exceeds 20% of the then effective borrowing base, and Berry Corp. demonstrates a pro forma leverage ratio less than or equal to 2.5 to 1.0. The conditions are currently met with significant margin.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 3—Derivatives
We utilize 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, which 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. Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations for up to 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, which we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions.
For fixed-price oil and gas 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 oil calls, we would receive settlement payments for prices above the indicated weighted-average price per barrel of Brent.
For fixed-price gas purchase swaps, we are the buyer so we make settlement payments for prices below the weighted-average price per MMBtu and receive settlement payments for prices above the weighted-average price per MMBtu.
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 these instruments are recorded in current earnings. Gains (losses) on oil and gas 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 $46.17 
Purchased Oil Calls Options (Brent):
Hedged volume (MBbls)276   
Weighted-average price ($/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 fixed price gas sales swaps at an average price of $2.96, indexed to Northwest Pipeline Rocky Mountains and CIG, for the period January 1, 2021 through December 31, 2021.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Our commodity derivatives are measured at fair value using industry-standard models with various inputs including publicly available underlying commodity prices and forward 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 September 30, 2020 and December 31, 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 

 December 31, 2019
 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$17,799 $(8,633)$9,166 
  Commodity ContractsNon-current assets773 (248)525 
Liabilities:
  Commodity ContractsCurrent liabilities(13,450)8,633 (4,817)
  Commodity ContractsNon-current liabilities(389)248 (141)
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.
We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our RBL Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standards & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives which partially mitigates the counterparty nonperformance risk.
Note 4—Lawsuits, Claims, Commitments and Contingencies
In the normal course of business, we, or our subsidiary, are the subject of, or party to, pending or threatened legal proceedings, contingencies and commitments involving a variety of matters that seek, or may seek, among
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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, fines and penalties, remediation costs, or injunctive or declaratory relief.
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 September 30, 2020 and December 31, 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, or our subsidiary, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of September 30, 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 a Carry and Earning Agreement with Encana, effective June 7, 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 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.
Note 5—Equity
Cash Dividends
Our Board of Directors approved a $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.
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. The Company repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million as of December 31, 2019. 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 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 obligate Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. For the nine months ended September 30, 2020, we did not repurchase any shares under the stock repurchase program.
Stock-Based Compensation
In March 2020, the Company granted awards of 1,817,656 shares of restricted stock units (“RSUs”), which will vest annually in equal amounts over three years and 1,278,877 performance-based restricted stock units (“PSUs”), which will cliff vest, if at all, at the end of a three year performance period subject to both an absolute total stockholder return (“Absolute TSR”) performance metric and a relative total stockholder return (“Relative TSR”)
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
performance metric, as further discussed and defined below. The fair value of these awards was approximately $32 million.
The RSUs awarded are solely time-based awards. The PSUs awarded include a market objective measured against both Absolute TSR and Relative TSR to the Vanguard World Fund - Vanguard Energy ETF index (the “Index”) over the performance period, assuming the reinvestment of dividends. Depending on the results achieved during the 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 fair value of the PSUs 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 at the date of grant 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 approximate three-year performance measurement period.
Note 6—Supplemental Disclosures to the Financial Statements
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 inventories 3,409 3,432 
Other652 846 
Total other current assets$20,318 $19,399 
Other non-current assets at September 30, 2020 and December 31, 2019, included approximately $8 million and $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
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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 $ 

Cash and cash equivalents consist 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 7—Earnings Per Share
We calculate basic earnings (loss) per share by dividing net income (loss) by the weighted-average number of common shares outstanding for each period presented. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, are considered common shares outstanding and are included in the computation of net income (loss) per share.
The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the three and nine months ended September 30, 2020 no incremental RSUs or PSUs were included in the diluted 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 no incremental PSUs were included in the EPS calculation due to their contingent nature.
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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)$50,523 
Weighted-average shares of common stock outstanding79,879 80,982 79,776 81,703 
Dilutive effect of potentially dilutive securities(1)
 69  145 
Weighted-average common shares outstanding - diluted79,879 81,051 79,776 81,848 
Diluted (loss) earnings per share$(0.24)$0.65 $(2.50)$0.62 
__________
(1)    No potentially dilutive securities were included in computing diluted (loss) earnings per share for the three and nine months ended September 30, 2020, because the 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 accounting standards in effect for the prior period. The new 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 revenue 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 reflects the consideration we expect to receive in exchange for those goods or services.
Oil, Natural Gas and NGLs
We recognize revenue from the sale of our oil, natural gas and NGL 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 amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when market prices are known). Our contracts with customers typically require payment within 30 days following invoicing.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Electricity Sales
The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market based on market pricing, which includes capacity payments. The majority of the portion sold from three of our cogeneration facilities is sold under long-term contracts to two California utility companies, based on market pricing. Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. 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 kilowatt 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 case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations.
Marketing 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 revenues 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 proved and unproved oil and natural gas properties whenever events or changes in circumstance indicate that a property’s carrying value may not be recoverable. If the carrying amount of the proved properties exceeds the estimated 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 income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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.
We evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results.
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 latter 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 the 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 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 not record an impairment charge for the second or third quarter of 2020, as there were no triggering events.
Note 10—Income Taxes
The COVID-19 pandemic and related economic repercussions, coupled with OPEC+ actions, 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. As a result, after evaluating the positive and negative evidence, we determined that it was more likely than not that a large portion of our tax credits recorded in 2019 and other deferred tax assets would not be realized. Accordingly, we recognized a valuation allowance on our deferred tax assets for the quarter ended March 31, 2020 in the amount of $51 million. As of the quarter 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 the computation and limitation of interest expense amounts and are applicable for tax years beginning on or after November 13, 2020. Early adoption is permitted for tax years beginning after December 31, 2017. We assessed the impact of these regulations being issued in the third quarter. As a result, we recognized the entirety of its $14 million of uncertain tax benefits that were recorded as of December 31, 2019. The recognition of these uncertain tax benefits did not affect the effective tax rate.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 11—Acquisition
In May 2020, we acquired approximately 740 net acres in 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 the 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 this property. We also acquired all existing idle wells on this property, some of which 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 this property.
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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 our interim unaudited consolidated financial statements and related notes presented in this Quarterly Report on Form 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, 2019 (the Annual Report) filed with the Securities and Exchange Commission (SEC). When we use the terms we, us, our, Berry, the Company or similar words 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”), or (ii) either Berry Corp. or Berry LLC.
Our Company
We are a western United States independent upstream energy company with 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 oil-rich reservoirs in the 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 low-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 unconventional resource plays. We also have assets in the low-cost, oil-rich reservoirs in the Uinta basin of Utah and low geologic risk, natural gas resource plays in the Piceance basin in Colorado. We believe that successful execution of our strategy across our low-declining production base and extensive inventory of identified drilling locations should 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
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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
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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 prices we pay for our natural gas purchases, which are affected by a variety of factors, including those discussed in Part II, Item 1A. “Risk Factors” in this Quarterly Report, as well as in Part I, Item 1A. “Risk Factors” in our Annual Report. Average oil prices were higher for the three months ended September 30, 2020 compared to the three months ended June 30, 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 experienced an adverse
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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. 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, the 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 of $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, 2020 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 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 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.
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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
Like other companies in the oil and 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 California, the jurisdiction, 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 also 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 2019 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
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of CalGEM's permitting processes for well 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 moratorium 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 new policy goals for the State of California and directs the state legislature and agencies to develop policies or conduct rulemakings in furtherance of these goals. Specifically, the order 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 Berry will depend on the nature of any final rules, regulations, policies, or legislation adopted by the 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.
Violations and liabilities with respect to any of the applicable laws and regulations, including those related to any environmental incident, could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, an inability to receive 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 shortages and increase costs or delay operations. For example, our operations have been and in the future 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 and rain.
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.
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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) general and administrative expenses; and (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. Adjusted EBITDA is a non-GAAP financial measure that we defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization (“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 items.
Operating Expenses
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, 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. Additionally, 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 oil and gas industry, our operations are 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.
As part of our commitment to creating long-term stockholder value, we strive to conduct our operations in an ethical, safe and responsible manner, to protect the environment and to take care of our 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, and incentivize our employees to perform at high standards, including through our annual short-term incentive program.
General and Administrative Expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead 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.
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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.
Capital Expenditures
For the three and nine months ended September 30, 2020, our capital expenditures were approximately $4 million and $57 million, respectively, on an accrual basis excluding capitalized overhead of approximately $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 California oil operations.
Toward the end of the first quarter we reduced our planned 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 prior year. We also anticipate oil production will be approximately 88% of total production in 2020, compared to 87% in 2019. Based on our current capital plan we expect to be able to fund our remaining 2020 capital development programs with cash flow from operations. Even in this low price environment we plan to live within Levered Free Cash Flow over 2020 and 2021 in the aggregate, and beyond.
The amount and timing of capital expenditures are within our control and subject to our management’s 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 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 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, 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 2020.
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Acquisition
In May 2020, we acquired approximately 740 net acres in 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 the 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 this property. We also acquired all existing idle wells on this property, some of which 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 this property.
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Summary By Area
The following table shows a summary by area of our selected historical financial information and operating data for the periods indicated.
California
(San Joaquin and Ventura basins)
Three Months Ended
September 30, 2020June 30, 2020September 30, 2019