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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 March 31, 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 April 30, 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)
March 31, 2021December 31, 2020
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents$97,362 $80,557 
Accounts receivable, net of allowance for doubtful accounts of $2,215 at March 31, 2021 and $2,215 at December 31, 2020
52,333 52,027 
Derivative instruments3,283 2,507 
Other current assets25,063 19,400 
Total current assets178,041 154,491 
Noncurrent assets:
Oil and natural gas properties 1,436,286 1,412,566 
Accumulated depletion and amortization(264,015)(235,259)
Total oil and natural gas properties, net1,172,271 1,177,307 
Other property and equipment112,072 112,145 
Accumulated depreciation(33,687)(31,368)
Total other property and equipment, net78,385 80,777 
Derivative instruments1,999  
Other noncurrent assets6,135 7,235 
Total assets$1,436,831 $1,419,810 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses$159,846 $151,985 
Derivative instruments52,719 23,321 
Total current liabilities212,565 175,306 
Noncurrent liabilities:
Long-term debt393,741 393,480 
Deferred income taxes635 1,011 
Asset retirement obligations135,402 135,192 
Other noncurrent liabilities2,694 785 
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 March 31, 2021 and December 31, 2020, respectively)
86 85 
Additional paid-in-capital914,956 915,877 
Treasury stock, at cost (5,112,246 shares at March 31, 2021 and December 31, 2020)
(49,995)(49,995)
Retained deficit (173,253)(151,931)
Total stockholders' equity691,794 714,036 
Total liabilities and stockholders' equity$1,436,831 $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
March 31,
20212020
(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales$135,265 $122,098 
Electricity sales10,069 5,461 
(Losses) gains on oil and gas sales derivatives(53,504)211,229 
Marketing revenues2,234 453 
Other revenues137 24 
Total revenues and other94,201 339,265 
Expenses and other:
Lease operating expenses62,284 50,752 
Electricity generation expenses7,648 3,946 
Transportation expenses1,576 1,822 
Marketing expenses2,227 430 
General and administrative expenses17,070 19,337 
Depreciation, depletion, and amortization33,840 35,329 
Impairment of oil and gas properties 289,085 
Taxes, other than income taxes9,557 4,352 
(Gain) losses on natural gas purchase derivatives(27,730)12,035 
Other operating expenses799 2,202 
Total expenses and other107,271 419,290 
Other (expenses) income:
Interest expense(8,485)(8,920)
Other, net(143)(6)
Total other (expenses) income(8,628)(8,926)
Loss before income taxes(21,698)(88,951)
Income tax (benefit) expense(376)26,349 
Net loss $(21,322)$(115,300)
Net loss per share:
Basic
$(0.27)$(1.45)
Diluted
$(0.27)$(1.45)

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)


Three-Month Period Ended March 31, 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, 2020$85 $904,072 $(49,995)$(4,336)$849,826 

Three-Month Period Ended March 31, 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, 2021
$86 $914,956 $(49,995)$(173,253)$691,794 


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)
Three Months Ended
March 31,
20212020
(in thousands)
Cash flows from operating activities:
Net loss$(21,322)$(115,300)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization33,840 35,329 
Amortization of debt issuance costs1,360 1,338 
Impairment of oil and gas properties 289,085 
Stock-based compensation expense3,779 2,922 
Deferred income taxes(376)26,347 
Increase in allowance for doubtful accounts 1,200 
Other operating expenses 1,575 
Derivative activities:
Total losses (gains)25,774 (199,194)
Cash settlements on derivatives850 19,625 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable (296)22,074 
(Increase) in other assets(5,663)(331)
Increase (decrease) in accounts payable and accrued expenses1,300 (29,179)
Decrease in other liabilities(816)(11,008)
Net cash provided by operating activities38,430 44,483 
Cash flows from investing activities:
Capital expenditures:
Capital expenditures(23,569)(39,703)
Changes in capital expenditures accruals3,508 (3,533)
Acquisition of properties and equipment and other (12)
Proceeds from sale of property and equipment and other124 210 
Net cash used in investing activities(19,937)(43,038)
Cash flows from financing activities:
Borrowings under RBL credit facility 124,100 
Repayments on RBL credit facility (115,000)
Dividends paid on common stock(246)(9,750)
Shares withheld for payment of taxes on equity awards and other(1,442)(794)
Net cash used in financing activities(1,688)(1,444)
Net increase in cash and cash equivalents16,805 1 
Cash and cash equivalents:
Beginning80,557  
Ending$97,362 $1 
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:
March 31,
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(6,259)(6,520)
Long-Term Debt, net$393,741 $393,480 
Deferred Financing Costs
We incurred legal and bank fees related to the issuance of debt. At March 31, 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 $6 million and $7 million net of amortization, respectively. At March 31, 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 March 31, 2021 and March 31, 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.
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 $388 million and $337 million at March 31, 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
6

Table of Contents
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 March 31, 2021, our Leverage Ratio and Current Ratio were 1.9 to 1.0 and 2.3 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 March 31, 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 March 31, 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 March 31, 2021, we had the following crude oil production and gas purchase hedges.
Q2 2021Q3 2021Q4 2021FY 2022
Fixed Price Oil Swaps (Brent):
  Hedged volume (mbbls)1,728 1,318 1,318 1,095 
  Weighted-average price ($/bbl)$45.82 $48.66 $48.66 $60.00 
Fixed Price Gas Purchase Swaps (Kern, Delivered):
  Hedged volume (mmbtu)4,777,500 4,830,000 2,085,000  
  Weighted-average price ($/mmbtu)$2.83 $2.83 $2.95 $ 
As of March 31, 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 January 1, 2021 through December 31, 2021. These swap positions effectively cancel each other while resulting in a mark-to-market gain of $2 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 March 31, 2021 and December 31, 2020:
March 31, 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$10,667 $(7,384)$3,283 
  Commodity ContractsNon-current assets1,999  1,999 
Liabilities:
  Commodity ContractsCurrent liabilities(60,103)7,384 (52,719)
Total derivatives$(47,437)$— $(47,437)
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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 any reserve balances at March 31, 2021 and 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 March 31, 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.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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, multiple plaintiffs filed motions in the Torres Lawsuit seeking 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 dividend of $0.04 per share on our common stock for the first quarter of 2021, which we paid in April 2021. In April 2021, our Board of Directors approved a $0.04 per share regular cash dividend on our common stock for the second quarter of 2021, which is expected to be paid in July 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. For the three months ended March 31, 2021, we did not repurchase any shares under the stock repurchase program.
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 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
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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:
March 31, 2021December 31, 2020
(in thousands)
Prepaid expenses$10,351 $3,592 
Materials and supplies10,876 11,666 
Oil inventories 3,609 3,490 
Other227 652 
Total other current assets$25,063 $19,400 
Other non-current assets at March 31, 2021 and December 31, 2020, included approximately $6 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:
March 31, 2021December 31, 2020
(in thousands)
Accounts payable-trade$22,498 $11,055 
Accrued expenses43,849 43,452 
Royalties payable16,921 15,150 
Greenhouse gas liability - current portion34,123 35,554 
Taxes other than income tax liability9,892 10,118 
Accrued interest3,500 10,783 
Dividends payable3,218  
Asset retirement obligations - current portion25,000 25,000 
Other845 873 
Total accounts payable and accrued expenses$159,846 $151,985 
The long-term portion of the asset retirement obligations remained flat at $135 million at March 31, 2021 and December 31, 2020 due to $3 million of accretion, which was offset by $3 million of liabilities settled during the period.
Other non-current liabilities at March 31, 2021 and December 31, 2020 included approximately $2 million and no greenhouse gas liability, respectively.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Supplemental Information on the Statement of Operations
For the three months ended March 31, 2021, other operating expense was $1 million and mainly consisted of oil tank storage fees. For three months ended March 31, 2020, other operating expense was $2 million and mainly consisted of excess abandonment costs and drilling rig standby charges.
Supplemental Cash Flow Information
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
Three Months Ended
March 31,
20212020
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties$1,020 $696 
Supplemental Disclosures of Cash Payments (Receipts):
  Interest, net of amounts capitalized$14,637 $14,879 
  Income taxes payments$ $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 $4 million and $2 million as of March 31, 2021 and December 31, 2020, respectively.
Note 7—Earnings Per Share
We calculate basic earnings (loss) per share by dividing net income (loss) by the weighted-average number of common shares outstanding for each period presented. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, are considered common shares outstanding and are included in the computation of net income (loss) per share.
The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the three months ended March 31, 2021 and 2020 no incremental RSUs or PSUs were included in the diluted EPS calculation as their effect was anti-dilutive under the “if converted” method.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
 Three Months Ended
March 31,
20212020
 (in thousands except per share amounts)
Basic EPS calculation
Net loss$(21,322)$(115,300)
Weighted-average shares of common stock outstanding80,115 79,608 
Basic loss per share$(0.27)$(1.45)
Diluted EPS calculation
Net loss$(21,322)$(115,300)
Weighted-average shares of common stock outstanding80,115 79,608 
Dilutive effect of potentially dilutive securities(1)
  
Weighted-average common shares outstanding - diluted80,115 79,608 
Diluted loss per share$(0.27)$(1.45)
__________
(1)    We excluded approximately 2.2 million and 0.3 million dilutive securities from the dilutive weighted-average common shares outstanding for the three months ended March 31, 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 months ended March 31, 2021 and 2020:
Three Months Ended
March 31,
20212020
(in thousands)
Oil sales$122,359 $118,310 
Natural gas sales12,077 3,368 
Natural gas liquids sales829 420 
Electricity sales10,069 5,461 
Marketing revenues2,234 453 
Other revenues137 24 
Revenues from contracts with customers147,705 128,036 
(Losses) gains on oil and gas sales derivatives(53,504)211,229 
Total revenues and other$94,201 $339,265 
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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, out-of-period and infrequent items.
15


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 beginning 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 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 mounting repercussions from both the COVID-19 pandemic and the industry downturn on our operations, our financial condition and our people.
The COVID-19 Pandemic and Industry Downturn
The recovery in the oil and gas industry has improved with generally increasing oil prices as more states and countries re-open and national and global economies continue to recover. The demand for oil, while improving, still remains below pre-COVID-19 pandemic levels and could again decline if there is a 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 addition, in April 2021, OPEC+ reached an agreement to gradually increase oil production over the next three months beginning in May 2021 as a result of anticipated global demand recovery.
As a result of the 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, which began in the first quarter of 2021, subject to future determination by the Company's Board of Directors.
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 March 31, 2021 compared to the three months ended December 31, 2020 and March 31, 2020. Brent crude oil contract prices ranged from $69.63 per bbl to $51.09 per bbl during the first 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 briefly higher than $100 per mmbtu and as low as $2.37 per mmbtu during the first quarter of 2021, while we paid an average of $7.99 per mmbtu in this period. In February 2021, due to Winter Storm Uri, we saw demand and prices for natural gas increase dramatically in all our markets.
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The following table presents the average Brent, WTI, Kern, Delivered, and Henry Hub prices for the three months ended March 31, 2021, December 31, 2020 and March 31, 2020:
Three Months Ended
March 31,
2021
December 31,
2020
March 31,
2020
Oil (bbl) – Brent$61.32 $45.26 $50.82 
Oil (bbl) – WTI$57.82 $42.66 $46.35 
Natural gas (mmbtu) – Kern, Delivered$7.99 $3.38 $1.97 
Natural gas (mmbtu) – Henry Hub$3.50 $2.52 $1.91 
As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 65% - 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.
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 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. 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.
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 2021 through December 2026. The contract ending in July 2021 represents less than 25% of our electricity sales. 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.
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
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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 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 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. 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.
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 regimen 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 and within the California's Department of Conservation (“DOC”). We have submitted the required plans to meet our obligations.
CalGEM 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, DOC 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 of CalGEM's permitting processes for well stimulation treatment, also known as hydraulic fracturing (“WST”), permits and project approval letters (“PALs”) for underground injection by the California Department of Finance and an independent
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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 were not, and our 2021 results are not expected to be, significantly impacted by the moratorium because our 2020 development and production plans did not, and our 2021 development and production plans do not, require new high-pressure cyclic steam injection permits and the moratorium does not impact existing production or previously approved permits.
Legislation passed in 2020 took effect January 1, 2021, which included expanded oil spill penalties and new reporting requirements for excavations and subsurface installations. Emergency measures passed in 2020 took effect immediately upon signature by the Governor, which included certain protections for workers and disclosure and reporting requirements related to COVID-19.
In September 2020, California Governor Gavin Newsom issued an executive order (the “Order”) that seeks to reduce both the supply of and demand for fossil fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: phasing out the sale of emissions-producing vehicles; developing strategies for the closure and repurposing of oil and gas facilities in California; and calling on the State Legislature to enact new laws prohibiting hydraulic fracturing in the state by 2024. The Order also directs CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations, which may include setbacks, to address these concerns by December 31, 2020, though this deadline was subsequently extended. In October 2020, the Governor issued an executive order that establishes a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directs state agencies to implement other measures to mitigate climate change and strengthen biodiversity. At this time, we cannot predict how implementation of these two executive orders may impact our operations.
In response to Governor Newsom's Order, in February 2021, California State Senators Scott Wiener and Monique Limón introduced Senate Bill 467, which proposed to halt the issuance or renewal of permits for hydraulic fracturing (fracking), acid well stimulation treatments, cyclic steaming, and water and steam flooding starting January 1, 2022, and then prohibit these extraction methods entirely starting January 1, 2027. As proposed, SB 467 also prohibited all new or renewed permits for oil and gas extraction within 2,500 feet of any homes, schools, healthcare facilities or long-term care institutions such as dormitories or prisons, by January 1, 2022. In April 2021, Senate Bill 467 failed to succeed through the first hearing of the Senate Natural Resources and Water Committee. While we expect another iteration of this proposed legislation will be reintroduced at a later time, the ultimate outcome, and therefore impact on our business, is not known and cannot be predicted. Past measures to impose additional stringent requirements upon oil and gas activities in the California legislature were not successful. For example, in both 2019 and 2020, California considered legislation to impose a statewide setback distance between certain oil and natural gas operations and residences, schools, and healthcare facilities. However, in both cases, the proposal failed to receive the approval of the California State Senate.

On April 23, 2021, Governor Newsom directed CalGEM to initiate rulemaking to halt the issuance of new WST permits, or permits for hydraulic fracturing, 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. In any event, given the limited use of hydraulic fracturing in our operations in California currently, we do not expect Governor Newsom’s April 23, 2021 executive order to have a material adverse impact on our operations. 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
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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.
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. Furthermore, in the first quarter of 2021, the United States experienced a sharp, and unusually large increase in natural gas prices caused by an historical February demand spike from Winter Storm Uri that impacted much of the nation. This caused, among other things, significantly increased revenues derived from our natural gas and electricity sales, driving significant increases in both revenues in the quarter.
Natural gas prices can 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.
Capital Expenditures
For three months ended March 31, 2021, our capital expenditures were approximately $24 million, on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement spending. Approximately 90% of total capital for the three months ended March 31, 2021 was directed to California oil operations.
Our planned 2021 capital expenditure budget is approximately $120 to $130 million, which we expect 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 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 over 2021 and 2022 in the aggregate, 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
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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 $23 million on plugging and abandonment activities, including satisfying our annual obligations under the California Idle Well Management Program.
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Summary by Area
The following table shows a summary by area of our selected historical financial information and operating data for the periods indicated.
California
(San Joaquin and Ventura basins)
Three Months Ended
March 31, 2021December 31, 2020March 31, 2020
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales
$113,177 $81,588 $109,519 
Operating income (loss)(1)
$18,965 $34,651 $(113,203)
Depreciation, depletion, and amortization (DD&A)
$32,896 $29,440 $30,918 
Impairment of oil and gas properties
$— $— $163,879 
Average daily production (mboe/d)
21.9 21.2 24.9 
Production (oil % of total)
100 %100 %100 %
Realized sales prices:
Oil (per bbl)
$57.34 $41.74 $48.38 
NGLs (per bbl)
$— $— $— 
Gas (per mcf)
$— $— $— 
Capital expenditures(2)
$22,760 $13,665 $38,627 
Utah
(Uinta basin)
Colorado
(Piceance basin)
Three Months EndedThree Months Ended
March 31,
2021
December 31,
2020
March 31,
2020
March 31,
2021
December 31,
2020
March 31,
2020
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales
$15,889 $10,453 $11,278 $6,194 $1,769 $1,299 
Operating income (loss)(1)
$7,433 $923 $(127,700)$5,039 $233 $384 
Depreciation, depletion, and amortization (DD&A)
$554 $911 $4,311 $38 $63 $55 
Impairment of oil and gas properties
$— $— $125,206 $— $— $— 
Average daily production (mboe/d)
4.0 4.1 4.5 1.2 1.3 1.4 
Production (oil % of total)
49 %50 %53 %%%%
Realized sales prices:
Oil (per bbl)
$52.08 $37.95 $39.64 $25.80 $10.23 $42.54 
NGLs (per bbl)
$26.81 $16.75 $13.16 $— $— $— 
Gas (per mcf)
$6.65 $3.04 $2.22 $9.83 $2.44 $1.70 
Capital expenditures(2)
$392 $385 $678 $$13 $
__________
(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
March 31, 2021December 31, 2020March 31, 2020
Average daily production:(1)
Oil (mbbl/d)23.9 23.3 27.3 
Natural Gas (mmcf/d)16.9 17.6 18.5 
NGL (mbbl/d)0.3 0.4 0.4 
Total (mboe/d)(2)
27.1 26.6 30.8 
Total Production:
Oil (mbbl)2,151 2,144 2,485 
Natural gas (mmcf)1,517 1,618 1,684 
NGLs (mbbl)31 37 32 
Total (mboe)(2)
2,435 2,450 2,798 
Weighted-average realized sales prices:
Oil without hedges ($/bbl)$56.89 $41.38 $47.61 
Effects of scheduled derivative settlements ($/bbl)$(12.08)$15.03 $9.67 
Oil with hedges ($/bbl)$44.81 $56.41 $57.28 
Natural gas ($/mcf)$7.96 $2.78 $2.00 
NGL ($/bbl)$26.81 $16.78 $13.16 
Average Benchmark prices:
Oil (bbl) – Brent$61.32 $45.26 $50.82 
Oil (bbl) – WTI$57.82 $42.66 $46.35 
Natural gas (mmbtu) – Kern, Delivered(3)
$7.99 $3.38 $1.97 
Natural gas (mmbtu) – Henry Hub(4)
$3.50 $2.52 $1.91 
__________
(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 March 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $61.32 per bbl and $3.50 per mmbtu.
(3)    Kern, Delivered Index is the relevant index used for gas purchases in California.
(4)    Henry Hub is the relevant index used for gas sales in the Rockies.
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The following table sets forth average daily production by operating area for the periods indicated:
Three Months Ended
March 31, 2021December 31, 2020March 31, 2020
Average daily production (mboe/d):(1)
California21.9 21.2 24.9 
Utah4.0 4.1 4.5 
Colorado1.2 1.3 1.4 
Total average daily production27.1 26.6 30.8 
__________
(1)    Production represents volumes sold during the period.
Average daily production increased 0.5 mboe/d, or 2%, and Company wide oil production increased 0.6 mboe/d, or 3%, for the three months ended March 31, 2021, compared to the three months ended December 31, 2020, largely due to increased development capital. Of the 50 wells drilled in the first quarter of 2021, five were delineation and 45 were production wells, a significant increase compared to the production well count of 22 in the fourth quarter of 2020. The increase is also attributable to well recompletions coming online during the first quarter 2021. Our California production of 21.9 mboe/d for the first quarter 2021 increased 3% from the fourth quarter 2020.
Average daily production volumes decreased 12% for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 due to significantly more development capital spending in the first quarter of 2020 and the full year 2019 compared to the first quarter of 2021 and the full year of 2020.


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Results of Operations
Three Months Ended March 31, 2021 compared to Three Months Ended December 31, 2020.
Three Months Ended
March 31, 2021December 31, 2020$ Change% Change
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales$135,265 $93,811 $41,454 44 %
Electricity sales10,069 6,724 3,345 50 %
(Losses) gains on oil and gas sales derivatives(53,504)(39,617)(13,887)35 %
Marketing and other revenues2,371 448 1,923 429 %
Total revenues and other$94,201 $61,366 $32,835 54 %
Revenues and Other
In the first quarter of 2021, the United States experienced a sharp, and unusually large increase in natural gas prices caused by an historical February demand spike from Winter Storm Uri that impacted much of the nation. This had a dramatic impact on both our natural gas and electricity sales, driving significant increases for the first quarter. The impact on our fuel gas cost in California was not nearly as pronounced due to our effective hedging program and our proactive reduction in fuel usage during the highly volatile period in February.
Oil, natural gas and NGL sales increased by $41 million, or 44%, to approximately $135 million for the three months ended March 31, 2021, compared to the three months ended December 31, 2020. The increase was driven by $33 million and $8 million of higher unhedged prices from oil and natural gas, respectively.
Electricity sales represent sales to utilities, and increased $3 million, or 50%, to approximately $10 million for the three months ended March 31, 2021 compared to the three months ended December 31, 2020. The increase was unseasonably high and reflected higher unit sales prices driven by higher natural gas prices, primarily attributed to Winter Storm Uri, during the first quarter 2021 compared to the fourth quarter 2020.
Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement loss for the three months ended March 31, 2021 was $26 million and the gain for the three months ended December 31, 2020 was $32 million. The quarter-over-quarter shift from settlement gains to settlement losses was driven by higher oil prices relative to the derivative fixed contract prices in the first quarter compared to those of the fourth quarter of 2020. The first quarter 2021 had an average derivative fixed price of $45.82 and daily notional volumes of 19 mbbls/d where the fourth quarter 2020 had an average derivative fixed price of $59.85 and daily notional volumes of 24 mbbls/d. The mark-to-market non-cash loss of $28 million for the three months ended March 31, 2021 was due to higher futures prices relative to the derivative fixed prices at March 31, 2021 compared to the non-cash loss of $72 million for the three months ended December 31, 2020.
Marketing and other revenues increased by $1.9 million for the three months ended March 31, 2021 when compared to the three months ended December 31, 2020 largely due to the natural gas demand spike in February.
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Three Months Ended
$ Change% Change
March 31, 2021December 31, 2020
(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses$62,284 $49,621 $12,663 26 %
Electricity generation expenses7,648 5,422 2,226 41 %
Transportation expenses1,576 1,559 17 %
Marketing expenses2,227 344 1,883 547 %
General and administrative expenses17,070 20,409 (3,339)(16)%
Depreciation, depletion and amortization33,840 30,434 3,406 11 %
Taxes, other than income taxes9,557 10,858 (1,301)(12)%
(Gain) losses on natural gas purchase derivatives(27,730)3,859 (31,589)n/a
Other operating expenses799 3,123 (2,324)(74)%
Total expenses and other107,271 125,629 (18,358)(15)%
Other (expenses) income:
Interest expense(8,485)(8,308)(177)%
Other, net(143)(13)(130)1,000 %
Loss before income taxes(21,698)(72,584)50,886 (70)%
Income tax benefit(376)(8,754)8,378 (96)%
Net loss$(21,322)$(63,830)$42,508 (67)%
Expenses per boe:(1)
Lease operating expenses$25.58 $20.25 $5.33 26 %
Electricity generation expenses3.14 2.21 0.93 42 %
Electricity sales(1)
(4.13)(2.74)(1.39)51 %
Transportation expenses0.65 0.64 0.01 %
Transportation sales(1)
(0.06)(0.04)(0.02)50 %
Marketing expenses0.92 0.14 0.78 557 %
Marketing revenues(1)
(0.92)(0.14)(0.78)557 %
Derivatives settlements received for gas purchases(1)
(10.78)(1.26)(9.52)756 %
Total operating expenses$14.40 $19.06 $(4.66)(24)%
Total unhedged operating expenses(2)
$25.18 $20.32 $4.86 24 %
Total non-energy operating expenses(3)
$12.74 $14.35 $(1.61)(11)%
Total energy operating expenses(4)
$1.66 $4.70 $(3.04)(65)%
General and administrative expenses(5)
$7.01 $8.33 $(1.32)(16)%
Depreciation, depletion and amortization$13.90 $12.42 $1.48 12 %
Taxes, other than income taxes$3.93 $4.43 $(0.50)(11)%
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(1)    We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also include the effect of derivative settlements (received or paid) for gas purchases.
(2)    Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3)    Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(4)    Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
(5)    Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.51 per boe and $2.26 per boe for the three months ended March 31, 2021 and December 31, 2020, respectively.
Expenses and Other
In accordance with GAAP, we report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues. However, these revenues are viewed and used internally in calculating operating expenses, which are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
Operating expenses are defined above in “How We Plan and Evaluate Operations”. In the first quarter of 2021 we experienced a sharp, and unusually large increase in natural gas prices caused by a demand spike from Winter Storm Uri that impacted much of the nation in February. For about one week in mid-February, daily gas prices exceeded $100 per mmbtu and during this time we temporarily modified our operations to reduce the amount of fuel gas required to be purchased, thereby avoiding approximately $7 million of additional costs. We were, and remain during 2021, largely hedged on our natural gas purchases against increases in purchase prices. On a hedged basis, operating expenses, decreased 24%, or $4.66 per boe and $12 million on an absolute dollar basis, to $14.40 in the first quarter 2021 from $19.06 in the fourth quarter 2020. The decrease was partially due to a favorable change in gas purchase hedge settlement gains of $9.52 per boe, $23 million on an absolute dollar basis, which offset 85% of the increased fuel price in the first quarter 2021. We also had a significant increase in our electricity sales due to the high gas prices in California, which positively impacted our operating expenses as we define them. Finally, our continuing emphasis on cost saving and efficiency initiatives, which began in the second quarter of 2020, again demonstrated meaningful results in the first quarter of the year as non-energy costs declined 11% compared to the fourth quarter of 2020.
Unhedged lease operating expenses per boe increased to $25.58, for the three months ended March 31, 2021, a 26% or $5.33 per boe increase compared to $20.25 per boe for the three months ended December 31, 2020 driven by $7.03 per boe of higher unhedged fuel costs for our California steam operations. Unhedged average fuel purchase price doubled to $6.93 per mmbtu in the first quarter 2021 compared to the three months ended December 31, 2020. Non-energy operating expense decreased $1.61 per boe as a result of lower surface facility costs of $1.16, $0.24 of outside services and $0.22 of well servicing and recompletion activity. Lease operating expenses include fuel, maintenance, labor including supervision, vehicles, workover expenses, field office, and tools and supplies. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Electricity generation expenses increased approximately 42% to $3.14 per boe for the three months ended March 31, 2021, compared to $2.21 per boe for the three months ended December 31, 2020 due to higher natural gas costs described above. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Gains and losses on natural gas purchase derivatives resulted in a $28 million gain for the three months ended March 31, 2021 and a loss of $4 million in the three months ended December 31, 2020. Settlement gains for each of the three months ended March 31, 2021 and December 31, 2020 were $26 million and $3 million, or $10.78 and $1.26 per boe, respectively, and increased due to higher gas prices. The mark-to-market valuation gain for the three months ended March 31, 2021 was $2 million compared to a $7 million loss for the prior quarter. Generally, because
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