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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 June 30, 2021
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 Exchange Act). Yes ☐    No 

Shares of common stock outstanding as of July 31, 2021          80,471,022



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)
June 30, 2021December 31, 2020
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents$74,918 $80,557 
Accounts receivable, net of allowance for doubtful accounts of $1,715 at June 30, 2021 and $2,215 at December 31, 2020
63,740 52,027 
Derivative instruments11,515 2,507 
Other current assets26,890 19,400 
Total current assets177,063 154,491 
Noncurrent assets:
Oil and natural gas properties 1,478,622 1,412,566 
Accumulated depletion and amortization(294,576)(235,259)
Total oil and natural gas properties, net1,184,046 1,177,307 
Other property and equipment114,558 112,145 
Accumulated depreciation(36,187)(31,368)
Total other property and equipment, net78,371 80,777 
Other noncurrent assets5,035 7,235 
Total assets$1,444,515 $1,419,810 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses$160,586 $151,985 
Derivative instruments61,476 23,321 
Total current liabilities222,062 175,306 
Noncurrent liabilities:
Long-term debt394,009 393,480 
Derivative instruments4,058  
Deferred income taxes538 1,011 
Asset retirement obligations139,181 135,192 
Other noncurrent liabilities6,009 785 
Commitments and Contingencies - Note 4
Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 85,583,268 and 85,041,581 shares issued; and 80,471,022 and 79,929,335 shares outstanding, at June 30, 2021 and December 31, 2020, respectively)
86 85 
Additional paid-in-capital914,701 915,877 
Treasury stock, at cost (5,112,246 shares at June 30, 2021 and December 31, 2020)
(49,995)(49,995)
Retained deficit (186,134)(151,931)
Total stockholders' equity678,658 714,036 
Total liabilities and stockholders' equity$1,444,515 $1,419,810 
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
June 30,
Six Months Ended
June 30,
2021202020212020
(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales$147,775 $70,515 $283,040 $192,613 
Electricity sales6,888 4,884 16,957 10,345 
(Losses) gains on oil and gas sales derivatives(55,653)(42,267)(109,157)168,962 
Marketing revenues121 292 2,355 745 
Other revenues118 29 255 53 
Total revenues and other99,249 33,453 193,450 372,718 
Expenses and other:
Lease operating expenses45,543 40,733 107,827 91,485 
Electricity generation expenses4,712 3,022 12,360 6,968 
Transportation expenses1,757 1,789 3,333 3,611 
Marketing expenses44 280 2,271 710 
General and administrative expenses16,065 18,777 33,135 38,114 
Depreciation, depletion, and amortization35,850 37,512 69,690 72,841 
Impairment of oil and gas properties   289,085 
Taxes, other than income taxes11,603 10,449 21,160 14,801 
(Gains) losses on natural gas purchase derivatives(11,639)925 (39,369)12,960 
Other operating expenses (income)42 (1,192)841 1,010 
Total expenses and other103,977 112,295 211,248 531,585 
Other (expenses) income:
Interest expense(8,217)(8,676)(16,702)(17,596)
Other, net(8)(6)(151)(12)
Total other (expenses) income(8,225)(8,682)(16,853)(17,608)
Loss before income taxes(12,953)(87,524)(34,651)(176,475)
Income tax (benefit) expense(72)(22,623)(448)3,726 
Net loss $(12,881)$(64,901)$(34,203)$(180,201)
Net loss per share:
Basic
$(0.16)$(0.81)$(0.43)$(2.26)
Diluted
$(0.16)$(0.81)$(0.43)$(2.26)

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

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


Six-Month Period Ended June 30, 2020
Common StockAdditional Paid-in CapitalTreasury StockRetained DeficitTotal Stockholders’ 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, 2020$85 $908,662 $(49,995)$(69,237)$789,515 

Six-Month Period Ended June 30, 2021
Common StockAdditional Paid-in CapitalTreasury Stock Retained DeficitTotal Stockholders’ Equity
(in thousands)
December 31, 2020$85 $915,877 $(49,995)$(151,931)$714,036 
Shares withheld for payment of taxes on equity awards and other
— (1,442)— — (1,442)
Stock based compensation
— 3,995 — — 3,995 
Issuance of common stock1 — — — 1 
Dividends declared on common stock, $0.04/share
— (3,474)— — (3,474)
Net loss
— — — (21,322)(21,322)
March 31, 202186 914,956 (49,995)(173,253)691,794 
Shares withheld for payment of taxes on equity awards and other
— (78)— — (78)
Stock based compensation
— 3,042 — — 3,042 
Dividends declared on common stock, $0.04/share
— (3,219)— — (3,219)
Net loss
— — — (12,881)(12,881)
June 30, 2021$86 $914,701 $(49,995)$(186,134)$678,658 


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

Table of Contents
BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
20212020
(in thousands)
Cash flows from operating activities:
Net loss$(34,203)$(180,201)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization69,690 72,841 
Amortization of debt issuance costs2,728 2,681 
Impairment of oil and gas properties 289,085 
Stock-based compensation expense6,639 7,501 
Deferred income taxes(473)2,750 
(Decrease) increase in allowance for doubtful accounts(500)1,200 
Other operating expenses142 317 
Derivative activities:
Total losses (gains)69,788 (156,002)
Cash settlements on derivatives(36,581)71,499 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable (11,189)21,802 
(Increase) in other assets(7,490)(3,642)
Increase (decrease) in accounts payable and accrued expenses3,406 (32,102)
(Decrease) in other liabilities(2,098)(11,307)
Net cash provided by operating activities59,859 86,422 
Cash flows from investing activities:
Capital expenditures:
Capital expenditures(67,030)(56,403)
Changes in capital expenditures accruals6,934 (7,256)
Acquisition of properties and equipment and other(825)(2,076)
Proceeds from sale of property and equipment and other409 217 
Net cash used in investing activities(60,512)(65,518)
Cash flows from financing activities:
Borrowings under RBL credit facility 222,550 
Repayments on RBL credit facility (223,100)
Dividends paid on common stock(3,466)(19,420)
Shares withheld for payment of taxes on equity awards and other(1,520)(934)
Net cash used in financing activities(4,986)(20,904)
Net increase in cash and cash equivalents(5,639) 
Cash and cash equivalents:
Beginning80,557  
Ending$74,918 $ 
The accompanying notes are an integral part of these condensed consolidated financial statements.
4

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 (primarily in the San Joaquin basin), 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, 2020.
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.
Recently Adopted Accounting Standards
In December 2019, the FASB issued rules which simplify the accounting for income taxes. We adopted these rules in the first quarter of 2021 which did not have a material impact on our financial statements.

5

Table of Contents
BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 2—Debt
The following table summarizes our outstanding debt:
June 30,
2021
December 31,
2020
Interest RateMaturitySecurity
(in thousands)
RBL Facility$ $ 
variable rates
3.0% (2021) and 4.0% (2020), 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 Amount400,000 400,000 
Less: Debt Issuance Costs(5,991)(6,520)
Long-Term Debt, net$394,009 $393,480 
Deferred Financing Costs
We incurred legal and bank fees related to the issuance of debt. At June 30, 2021 and December 31, 2020, debt issuance costs for the RBL Facility (as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $5 million and $7 million net of amortization, respectively. At June 30, 2021 and December 31, 2020, debt issuance costs, net of amortization, for the unsecured notes due February 2026 (the “2026 Notes”) reported in “Long-Term Debt, net” on the balance sheet were approximately $6 million and $7 million, respectively.
For the three months ended June 30, 2021 and 2020, the amortization expense for the RBL Facility and 2026 Notes were both approximately $1 million and was included in “interest expense” in the condensed consolidated statements of operations. For each of the six month periods ended June 30, 2021 and 2020, the amortization expense for both the RBL Facility and 2026 Notes was approximately $3 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 $408 million and $337 million at June 30, 2021 and December 31, 2020, respectively.
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”). The RBL Facility 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 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 has an elected commitment feature that allows us to increase commitments to the amount of our borrowing base with lender approval. In April 2021, we completed our scheduled semi-annual borrowing base redetermination under our RBL Facility, which resulted in a reaffirmed borrowing base and the Company's elected commitment at $200 million with no further borrowing restrictions beyond the covenants noted below.
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 contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans on a weekly basis in the amount of any
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
cash on the balance sheet (subject to certain exceptions) in excess of $30 million; and further limits to dividends and share repurchases. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.
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 June 30, 2021, our Leverage Ratio and Current Ratio were 2.1 to 1.0 and 2.2 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 June 30, 2021.
The RBL Facility permits us to repurchase equity and indebtedness, among other things, if availability is equal to or greater than 20% of the elected commitments or borrowing base, whichever is in effect, and our pro forma leverage ratio is less than or equal to 2.5 to 1.0.
As of June 30, 2021, we had no borrowings outstanding, $7 million in letters of credit outstanding, and approximately $193 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.
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, which includes capital needed to sustain production levels, as well as interest and dividends as applicable, 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.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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 June 30, 2021, we had the following crude oil production and gas purchase hedges.
Q3 2021Q4 2021FY 2022
Fixed Price Oil Swaps (Brent):
Hedged volume (mbbls)1,318 1,318 1,095 
Weighted-average price ($/bbl)$48.66 $48.66 $60.00 
Fixed Price Gas Purchase Swaps (Kern, Delivered):
Hedged volume (mmbtu)4,830,000 2,085,000  
Weighted-average price ($/mmbtu)$2.83 $2.95 $ 
As of June 30, 2021 we also had open swap positions that are excluded from the table above where we are both buyer and seller of equal notional volumes of 12,500 mmbtu/d of fixed price gas sales swaps each indexed to Northwest Pipeline Rocky Mountains and CIG, for the period July 1, 2021 through December 31, 2021. These swap positions effectively cancel each other while resulting in a mark-to-market gain of $1 million. This gain will be cash settled in 2021 as the positions expire.
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 June 30, 2021 and December 31, 2020:
June 30, 2021
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)
Assets:
  Commodity ContractsCurrent assets$20,876 $(9,361)$11,515 
Liabilities:
  Commodity ContractsCurrent liabilities(70,837)9,361 (61,476)
  Commodity ContractsNon-current liabilities(4,058) (4,058)
Total derivatives$(54,019)$— $(54,019)
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)

 December 31, 2020
 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)
Assets:
  Commodity ContractsCurrent assets$15,217 $(12,710)$2,507 
Liabilities:
  Commodity ContractsCurrent liabilities(36,031)12,710 (23,321)
Total derivatives$(20,814)$— $(20,814)
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 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 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 a material balance at June 30, 2021 or December 31, 2020. 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 accruals 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 June 30, 2021, 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 continue to defend the matter vigorously, however, given the uncertainty of litigation and the stage of the case, among other things, at this time we cannot estimate the likelihood or an amount of possible loss, that may result from this action.
We recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that will reduce our exposure to fuel gas purchase price fluctuations. These capacity
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
agreements are for approximately 10,000 mmbtu/d beginning October 2021 through October 2036 and approximately 5,500 mmbtu/d beginning November 2021 through December 2024 for a total commitment of $32 million.
Securities Litigation Matter
On November, 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against Berry Corp. and certain of its current and former directors and officers (the “Defendants”). The complaint alleges that the Defendants made false and misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined following release of its financial results for the third quarter of 2020. The complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs.
On January 21, 2021, motions were filed in the Torres Lawsuit as plaintiffs sought to be appointed lead plaintiff and lead counsel. We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the preliminary stage of the case, and the legal standards that must be met for, among other things, class certification and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this action.
Note 5—Equity
Cash Dividends
Our Board of Directors approved a regular cash dividend of $0.04 per share on our common stock for the first and second quarters of 2021. We paid the first and the second quarter cash dividend in April and July 2021, respectively. The Board of Directors approved a $0.06 per share regular cash dividend on our common stock for the third quarter of 2021, which is expected to be paid in October 2021.
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 the time, they authorized 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 in 2018 and 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. We have not repurchased any shares under the stock repurchase program since 2019.
Stock-Based Compensation
In February 2021, the Company granted awards of 1,832,941 shares of restricted stock units (“RSUs”), which will vest annually in equal amounts over three years and 997,840 performance-based restricted stock units (“PSUs”), which will cliff vest, if at all, at the end of a three year performance period. The fair value of these awards was approximately $14 million.
The RSUs awarded in February 2021 are solely time-based awards. Of the PSUs awarded in February 2021, (a) 50% of such will vest, if at all, based on a total stockholder return (“TSR”) performance metric (the “TSR PSUs”), which is defined as the capital gains per share of stock plus dividends paid assuming reinvestment, with TSR
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
measured on an absolute basis and relative to the TSR of the 39 exploration and production companies in the Vanguard World Fund - Vanguard Energy ETF Index plus the S&P SmallCap 600 Value Index (collectively, the “Peer Group”) during the performance period; and (b) the other 50% of such will vest, if at all, based on the Company's average cash returned on invested capital (“CROIC PSUs”) over the performance period. 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 250% of the TSR PSUs granted and from 0% to 200% of the CROIC PSUs granted.
The fair value of the RSUs and CROIC PSUs was determined using the grant date stock price. The fair value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the Peer Group 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:
June 30, 2021December 31, 2020
(in thousands)
Prepaid expenses$12,544 $3,592 
Materials and supplies10,847 11,666 
Oil inventories 3,273 3,490 
Other226 652 
Total other current assets$26,890 $19,400 
Other non-current assets at June 30, 2021 and December 31, 2020, included approximately $5 million and $7 million of deferred financing costs, net of amortization, respectively.
Accounts payable and accrued expenses on the condensed consolidated balance sheets included the following:
June 30, 2021December 31, 2020
(in thousands)
Accounts payable-trade$11,820 $11,055 
Accrued expenses56,223 43,452 
Royalties payable17,522 15,150 
Greenhouse gas liability - current portion29,060 35,554 
Taxes other than income tax liability11,439 10,118 
Accrued interest10,500 10,783 
Dividends payable3,217  
Asset retirement obligations - current portion20,000 25,000 
Other805 873 
Total accounts payable and accrued expenses$160,586 $151,985 
The increase of $4 million in the long-term portion of the asset retirement obligations from $135 million at December 31, 2020 to $139 million at June 30, 2021 was due to $5 million of accretion, $1 million of liabilities incurred and reclassification of $5 million from current to long-term portion due to changes in anticipated spending and regulatory requirements. These increases were partially offset by $7 million of liabilities settled during the period.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Other non-current liabilities at June 30, 2021 and December 31, 2020 included approximately $5 million and no greenhouse gas liability, respectively.
Supplemental Information on the Statement of Operations
For the three months ended June 30, 2021, other operating expense mainly consisted of $2 million of supplemental property tax assessments and royalty audit charges, mostly offset by $2 million of employee retention credits. For three months ended June 30, 2020, other operating income was $1 million and mainly consisted of sales tax and bankruptcy-related refunds, partially offset by excess abandonment costs and drilling rig standby charges.
For the six months ended June 30, 2021 and 2020 other operating expenses were $1 million. For the six months ended June 30, 2021, other operating expenses mainly consisted of approximately $3 million of supplemental property tax assessments and royalty audit charges and tank rental costs, partially offset by $2 million of employee retention credits. For the six months ended June 30, 2020, other operating expense mainly consist of excess abandonment costs, drilling rig standby charges, partially offset by sales tax and bankruptcy-related refunds.
Supplemental Cash Flow Information
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
Six Months Ended
June 30,
20212020
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties$1,437 $911 
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized$14,925 $15,527 
Income taxes payments$ $2 
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 approximately $2 million as of June 30, 2021 and December 31, 2020.
Note 7—Earnings Per Share
We calculate basic earnings (loss) per share by dividing net income (loss) by the weighted-average number of common shares outstanding for each period presented. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, are considered common shares outstanding and are included in the computation of net income (loss) per share.
The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the three and six months ended June 30, 2021 and 2020, no incremental RSUs or PSUs were included in the diluted EPS calculation as their effect was anti-dilutive under the “if converted” method.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
 Three Months Ended
June 30,
Six Months Ended
June 30,
2021202020212020
 (in thousands except per share amounts)
Basic EPS calculation
Net loss$(12,881)$(64,901)$(34,203)$(180,201)
Weighted-average shares of common stock outstanding80,471 79,795 80,294 79,702 
Basic loss per share$(0.16)$(0.81)$(0.43)$(2.26)
Diluted EPS calculation
Net loss$(12,881)$(64,901)$(34,203)$(180,201)
Weighted-average shares of common stock outstanding80,471 79,795 80,294 79,702 
Dilutive effect of potentially dilutive securities(1)
    
Weighted-average common shares outstanding - diluted80,471 79,795 80,294 79,702 
Diluted loss per share$(0.16)$(0.81)$(0.43)$(2.26)
__________
(1)    We excluded approximately 2.9 million and 0.8 million dilutive securities from the dilutive weighted-average common shares outstanding for the three months ended June 30, 2021 and 2020, because their effect was anti-dilutive. We excluded approximately 2.6 million and 0.8 million dilutive securities from the dilutive weighted-average common shares outstanding for the six months ended June 30, 2021 and 2020, because their effect was anti-dilutive.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 8—Revenue Recognition
We derive most of our revenue from sales of oil, natural gas and NGLs, with the remaining revenue generated from sales of electricity and marketing activities related to transporting and marketing third-party volumes.
The following table provides disaggregated revenue for the three and six months ended June 30, 2021 and 2020:
Three Months Ended
June 30,
Six Months Ended
June 30,
2021202020212020
(in thousands)
Oil sales$141,309 $67,512 $263,668 $185,822 
Natural gas sales5,415 2,834 17,492 6,202 
Natural gas liquids sales1,051 169 1,880 589 
Electricity sales6,888 4,884 16,957 10,345 
Marketing revenues121 292 2,355 745 
Other revenues118 29 255 53 
Revenues from contracts with customers154,902 75,720 302,607 203,756 
(Losses) gains on oil and gas sales derivatives(55,653)(42,267)(109,157)168,962 
Total revenues and other$99,249 $33,453 $193,450 $372,718 
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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, 2020 (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), a Delaware corporation (formerly known as Berry Petroleum Corporation, and also referred to herein as Berry Corp.”) together with its wholly owned subsidiary, Berry Petroleum, LLC, a Delaware limited liability company (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 focused on the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California.
In the aggregate, our assets are characterized by high oil content. The overwhelming majority of our productive 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, which enables 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-operating cost, oil-rich reservoirs in the Uinta basin of Utah and in the low geologic risk natural gas resource play in the Piceance basin in Colorado. We believe that the successful execution of our strategy across our low-declining, oil-weighted production base coupled with extensive inventory of identified drilling locations with attractive full-cycle economics will support our objectives to generate “Levered Free Cash Flow” (a non-GAAP financial measure discussed under “How We Plan and Evaluate Operations” in this report) to fund our operations, optimize capital efficiency, and return capital to stockholders, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles.
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.
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.
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 define 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 and infrequent items.
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Operating Expenses
Overall, operating expense is used by management as a measure of the efficiency with which operations are performed. 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. 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. Marketing revenues represent sales of natural gas purchased from and sold to third parties. 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, holding our employees and contractors to high standards. Meeting corporate EH&S metrics, including with respect to health and safety and spill prevention, is a part of our short-term incentive program for all employees.
General and Administrative Expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities and approximately 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.
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.
Business Environment, Market Conditions and Outlook
Our operating and financial results, same as 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. Our 2020 operating and financial results were adversely impacted by the deterioration and prolonged weakness in commodity prices that resulted from the COVID-19 pandemic as well as from certain actions by foreign oil and gas producers. Oil prices began to improve toward the end of 2020 and further strengthened in the first half of 2021.
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The extent to which our full year 2021 operating and financial results, or that of future periods, will be adversely impacted by the ongoing COVID-19 pandemic and the actions of foreign oil and gas producers will depend largely on future developments, which are highly uncertain and cannot be accurately predicted. 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 challenges and mitigate repercussions from both the COVID-19 pandemic and further industry downturns on our operations, our financial condition and our people.
The recovery in the oil and gas industry has improved with increasing oil prices as more states and countries re-open and national and global economies continue to recover. The demand for oil, while improving, could again decline if there is a widespread resurgence of the COVID-19 outbreak, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time. In July 2021, OPEC+ reached an agreement to continue gradually increasing oil production through the end of 2022, as global demand grows.
As a result of the 2020 industry downturn, commodity price outlook, and increasing uncertainty, we heightened our focus on driving operational efficiencies and reducing costs. As a result of our ability to accomplish this goal we reinstated a quarterly dividend in the first quarter of 2021, which was increased for the third quarter of 2021.
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 June 30, 2021 compared to the three months ended March 31, 2021 and June 30, 2020. Brent crude oil contract prices ranged between $62.15 per bbl and $76.18 per bbl during the second quarter of 2021. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. As described above, if reactions to 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.
In California, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, which was as high as $7.56 per mmbtu and as low as $2.37 per mmbtu during the second quarter of 2021, while we paid an average of $3.31 per mmbtu in this period.
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The following table presents the average Brent, WTI, Kern, Delivered, and Henry Hub prices for the three months ended June 30, 2021, March 31, 2021 and June 30, 2020 and for the six months ended June 30, 2021 and June 30, 2020:
Three Months EndedSix Months Ended
June 30,
2021
March 31,
2021
June 30,
2020
June 30,
2021
June 30,
2020
Oil (bbl) – Brent$69.08 $61.32 $33.39 $65.23 $42.10 
Oil (bbl) – WTI$66.03 $57.82 $28.42 $61.95 $37.38 
Natural gas (mmbtu) – Kern, Delivered$3.23 $7.99 $1.45 $5.60 $1.73 
Natural gas (mmbtu) – Henry Hub$2.95 $3.50 $1.70 $3.22 $1.80 
As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 65% to 70% of the state’s demand from OPEC+ countries and other waterborne sources. 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.
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. However, we have high operational control of our existing acreage, which provides significant upside for additional vertical and or horizontal development and recompletions.
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 the Rockies. Additionally, in recent history, the California gas markets have generally 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. We recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that will reduce our exposure to fuel gas purchase price fluctuations. Additionally, the negative impact of higher gas prices on our California operating expenses is partially offset by higher gas sales for the gas we produce and sell in the Rockies.
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.
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 short and long-term contracts with terms ending in September 2021 through December 2026. The contract ending in September 2021 represents less than 30% of our electricity sales in the six months ended June 30, 2021. 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, most notably in June through September, due to negotiated capacity payments we receive.
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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 use, land use, managing greenhouse gases or other emissions, protection of health, safety and the environment, protection of air quality, and the transportation, marketing, and sale of our products. Congress and federal and state agencies frequently revise the safety and environmental laws and regulations applicable to our operations, and any changes that result in more stringent and costly requirements for the oil and natural gas industry, for example for waste handling, disposal, cleanup and abandonment, could have a significant impact on operating and financial results. In many of these areas, federal, state, and local agencies may assert overlapping authority and regulations. In addition, new laws and regulations could apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors have no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
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 help ensure that we can realize the full potential of our resources in a manner that safeguards people and the environment and complies with existing laws and regulations. We monitor our environmental, health and safety, or EH&S, performance through various measures, and we hold our employees and contractors to high standards. Meeting corporate EH&S metrics, including with respect to EH&S incidents and spill prevention, is a part of our short-term incentive program for all employees. In 2020, we achieved a Total Recordable Incident Rate, or TRIR, of 0.5, which we believe, based on available data, is a record company low and is below the United States average for all industries, which is a TRIR of 3.0 based on the most recently available data.
Certain actions of the new U.S. administration could negatively impact the oil and gas industry. Such actions may include, among other things, the increased regulation of greenhouse gas emissions associated with oil and gas operations, the imposition of a new carbon tax on greenhouse gas emissions and replacing tax incentives related to fossil fuel with incentives for clean energy production. Such outcomes could materially and adversely affect our business, results of operations and financial condition.
Additionally, 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. Certain state legislators have recently sought to introduce new legislation to restrict oil and gas activities in California, however, those efforts have not been successful to date. Additionally, California Governor Gavin Newsome has advocated for and directed actions, including through executive orders, to restrict the oil and gas operations and reduce both the supply and demand for oil and gas in the state. Most recently, for example:
On April 23, 2021, Governor Newsom directed the California Geologic Energy Management Division (“CalGEM”) of the Department of Conservation, California's primary regulator of the oil and natural gas industry on private and state lands, to initiate rulemaking to halt the issuance of new permits for well stimulation treatments by 2024. It remains unclear whether or not CalGEM has existing statutory authority to take such action or whether additional enabling legislation from the California State Legislature is required. The directive also instructed the California Air Resources Board to evaluate regulatory pathways for phasing out oil extraction by 2045 under the state’s climate change scoping plan, which is the state’s comprehensive, programmatic plan to achieve the state’s required reductions in GHG emissions. We cannot predict the ultimate outcome of this evaluation, but authority for any rulemaking to broadly prohibit the extraction of oil would likely require the introduction of new legislation and be subject to significant opposition. As noted above, other proposals to prohibit or restrict certain oil extraction methods have previously been unsuccessful in the California State Legislature.
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In response to Governor Newsom’s April 23 directive explained above, in May 2021, CalGEM published pre-rulemaking draft regulations prohibiting authorizations for well stimulation treatments after January 1, 2024. Well stimulation treatments covered by the draft rule include hydraulic fracturing, acid fracturing, acid-matrix stimulation, and other well-stimulation treatments that enhance oil and gas production by creating channels in rock formations for hydrocarbons to flow. Separately, in July 2021, CalGEM denied a set of permits for hydraulic fracturing requested by an operator, generally citing the protection of public health and safety and environmental quality. While the operator has indicated it will appeal this decision, we cannot predict the ultimate outcome of any such appeal, and CalGEM could issue similar permit denials in the future for other operators. Given the limited use of hydraulic fracturing in our operations in California currently, we do not expect to be materially impacted by a potential final rule from CalGEM. However, our current operations and future plans may be impacted by pending or threatened legislative, regulatory changes or other government activity impacting the timing of, and conditions imposed on, the required permits and approvals governing our activities.
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 and completion 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 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.
Natural gas prices fluctuate based on seasonal and other market-related impacts. We purchase significantly more gas than we sell to generate steam and electricity in our cogeneration facilities for our producing activities. As a result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of this exposure by selling excess electricity from our cogeneration operations to third parties. The pricing of these electricity sales is closely tied to the purchase price of natural gas. These sales are generally higher in the summer months as they include seasonal capacity amounts. We also hedge a significant portion of the gas we expect to consume and we recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our operations in California.
Capital Expenditures
For the three and six months ended June 30, 2021, our capital expenditures were approximately $43 million and $67 million, respectively, on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement spending. Approximately 78% and 14% of total capital for the six months ended June 30, 2021 was directed to California oil and Utah operations, respectively .
Our planned 2021 capital expenditure budget is approximately $120 to $130 million. We plan to spend the majority of this amount during the second and third quarters of 2021. We expect our capital expenditures will result in essentially flat year-over year production and a higher exit rate for 2021 than 2020. We currently anticipate oil production will be approximately 89% of total production in 2021, compared to 88% in 2020. Based on current
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commodity prices and our drilling success rate to date, we expect to be able to fund our 2021 capital development programs with cash flow from operations and, if necessary, current cash on hand, which was generated during 2020 and anticipated for use to supplement our 2021 capital program. We plan to live within Levered Free Cash Flow in 2021 and beyond.
The amount and timing of capital expenditures are within our control and subject to our discretion, and due to the speed with which we are able to drill and complete our wells in California, capital may be adjusted quickly during the year depending on numerous factors, including commodity prices, storage constraints, supply/demand considerations and attractive rates of return. We believe it is important to retain the flexibility to defer planned capital expenditures and may do so based 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. Any postponement or elimination of our development drilling program could result in a reduction of proved reserves volumes and materially affect our business, financial condition and results of operations. Additionally and not included in the capital expenditures noted above, for the full year 2021, we plan to spend approximately $19 million to $23 million on plugging and abandonment activities, including satisfying our annual obligations under the California Idle Well Management Program.
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Summary by Area
The following table shows a summary by area of our selected historical financial information and operating data for the periods indicated.
California
(San Joaquin and Ventura basins)
Three Months Ended
June 30, 2021March 31, 2021June 30, 2020
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales
$129,128 $113,177 $62,943 
Operating income(1)
$11,413 $18,965 $32,469 
Depreciation, depletion, and amortization (DD&A)
$35,174 $32,896 $36,518 
Average daily production (mboe/d)
21.7 21.9 23.4 
Production (oil % of total)
100 %100 %100 %
Realized sales prices:
Oil (per bbl)
$65.37 $57.34 $29.53 
NGLs (per bbl)
$— $— $— 
Gas (per mcf)
$— $— $— 
Capital expenditures(2)
$31,303 $22,760 $16,446 
Utah
(Uinta basin)
Colorado
(Piceance basin)
Three Months EndedThree Months Ended
June 30,
2021
March 31,
2021
June 30,
2020
June 30,
2021
March 31,
2021
June 30,
2020
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales
$16,199 $15,889 $6,439 $2,438 $6,194 $1,132 
Operating income (loss)(1)
$6,736 $7,433 $(584)$1,121 $5,039 $
Depreciation, depletion, and amortization (DD&A)
$630 $554 $905 $38 $38 $43 
Average daily production (mboe/d)
4.4 4.0 4.4 1.2 1.2 1.3 
Production (oil % of total)
52 %49 %49 %%%%
Realized sales prices:
Oil (per bbl)
$58.55 $52.08 $23.11 $56.05 $25.80 $20.67 
NGLs (per bbl)
$29.61 $26.81 $5.82 $— $— $— 
Gas (per mcf)
$3.30 $6.65 $1.68 $3.53 $9.83 $1.53 
Capital expenditures(2)
$9,162 $392 $81 $— $$145 
__________
(1)    Operating income (loss) includes oil, natural gas and NGL sales, and scheduled oil derivative settlements, offset by operating expenses (as defined elsewhere), general and administrative expenses, DD&A, impairment of oil and gas properties, and taxes, other than income taxes.
(2)    Excludes corporate capital expenditures.
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Production and Prices
The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.
Three Months Ended
June 30, 2021March 31, 2021June 30, 2020
Average daily production:(1)
Oil (mbbl/d)24.0 23.9 25.6 
Natural Gas (mmcf/d)17.5 16.9 19.2 
NGL (mbbl/d)0.4 0.3 0.3 
Total (mboe/d)(2)
27.3 27.1 29.1 
Total Production:
Oil (mbbl)2,183 2,151 2,330 
Natural gas (mmcf)1,595 1,517 1,746 
NGLs (mbbl)36 31 29 
Total (mboe)(2)
2,485 2,435 2,650 
Weighted-average realized sales prices:
Oil without hedges ($/bbl)$64.72 $56.89 $28.98 
Effects of scheduled derivative settlements ($/bbl)$(18.33)$(12.08)$25.42 
Oil with hedges ($/bbl)$46.39 $44.81 $54.40 
Natural gas ($/mcf)$3.39 $7.96 $1.62 
NGL ($/bbl)$29.61 $26.81 $5.82 
Average Benchmark prices:
Oil (bbl) – Brent$69.08 $61.32 $33.39 
Oil (bbl) – WTI$66.03 $57.82 $28.42 
Natural gas (mmbtu) – Kern, Delivered(3)
$3.23 $7.99 $1.45 
Natural gas (mmbtu) – Henry Hub(4)
$2.95 $3.50 $1.70 
__________
(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 three months ended June 30, 2021, the average prices of Brent oil and Henry Hub natural gas were $69.08 per bbl and $2.95 per mmbtu.