BRY

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☒						QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☐						TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Delaware (State of incorporation or organization)						81-5410470 (I.R.S. Employer Identification Number)

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

Large accelerated filer ☐

Accelerated filer ☒

Non-accelerated filer ☐

Smaller reporting company ☐

Emerging Growth Company ☒

						Page
Part I – Financial Information
Item 1.			Financial Statements (unaudited)
			Condensed Consolidated Balance Sheets			1
			Condensed Consolidated Statements of Operations			2
			Condensed Consolidated Statements of Stockholders’ Equity			3
			Condensed Consolidated Statements of Cash Flows			4
			Notes to Condensed Consolidated Financial Statements			5
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
Item 3.			Quantitative and Qualitative Disclosures About Market Risk			54
Item 4.			Controls and Procedures			54
Part II – Other Information
Item 1.			Legal Proceedings			55
Item 1A.			Risk Factors			55
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities			56
Item 6.			Exhibits			57
			Glossary of Terms			58
			Signatures			66

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.

(Unaudited)

			March 31, 2022						December 31, 2021
			(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents			$	17,960					$	15,283
Accounts receivable, net of allowance for doubtful accounts of $866 at March 31, 2022 and $866 at December 31, 2021			111,961						86,269
Other current assets			36,567						45,946
Total current assets			166,488						147,498
Noncurrent assets:
Oil and natural gas properties			1,585,525						1,537,894
Accumulated depletion and amortization			(372,136)						(340,328)
Total oil and natural gas properties, net			1,213,389						1,197,566
Other property and equipment			151,479						140,710
Accumulated depreciation			(41,840)						(36,927)
Total other property and equipment, net			109,639						103,783
Derivative instruments			—						1,070
Deferred income taxes			171						—
Other noncurrent assets			5,040						6,562
Total assets			$	1,494,727					$	1,456,479
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses			$	154,084					$	157,524
Derivative instruments			92,472						29,625
Total current liabilities			246,556						187,149
Noncurrent liabilities:
Long-term debt			394,846						394,566
Derivative instruments			56,208						18,577
Deferred income taxes			—						1,831
Asset retirement obligations			142,999						143,926
Other noncurrent liabilities			23,692						17,782
Commitments and Contingencies - Note 4
Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 86,342,808 and 85,590,417 shares issued; and 80,759,540 and 80,007,149 shares outstanding, at March 31, 2022 and December 31, 2021, respectively)			86						86
Additional paid-in-capital			907,059						912,471
Treasury stock, at cost (5,583,268 and 5,583,268 shares at March 31, 2022 and December 31, 2021, respectively)			(52,436)						(52,436)
Retained deficit			(224,283)						(167,473)
Total stockholders' equity			630,426						692,648
Total liabilities and stockholders' equity			$	1,494,727					$	1,456,479

			Three Months Ended March 31,
			2022						2021
			(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales			$	210,351					$	135,265
Services revenue			39,836						—
Electricity sales			5,419						10,069
Losses on oil and gas sales derivatives			(161,858)						(53,504)
Marketing revenues			289						2,234
Other revenues			45						137
Total revenues and other			94,082						94,201
Expenses and other:
Lease operating expenses			63,124						62,284
Costs of services			33,472						—
Electricity generation expenses			4,463						7,648
Transportation expenses			1,158						1,576
Marketing expenses			299						2,227
General and administrative expenses			22,942						17,070
Depreciation, depletion, and amortization			39,777						33,840
Taxes, other than income taxes			6,605						9,557
Gains on natural gas purchase derivatives			(29,054)						(27,730)
Other operating expenses			3,769						799
Total expenses and other			146,555						107,271
Other (expenses) income:
Interest expense			(7,675)						(8,485)
Other, net			(13)						(143)
Total other (expenses) income			(7,688)						(8,628)
Loss before income taxes			(60,161)						(21,698)
Income tax benefit			(3,351)						(376)
Net loss			$	(56,810)					$	(21,322)
Net loss per share:
Basic			$	(0.71)					$	(0.27)
Diluted			$	(0.71)					$	(0.27)

			Three-Month Period Ended March 31, 2021
			Common Stock						Additional Paid-in Capital						Treasury Stock						Retained Deficit						Total 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 stock			1						—						—						—						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

			Three-Month Period Ended March 31, 2022
			Common Stock						Additional Paid-in Capital						Treasury Stock						Retained Deficit						Total Stockholders’ Equity
			(in thousands)
December 31, 2021			$	86					$	912,471					$	(52,436)					$	(167,473)					$	692,648
Shares withheld for payment of taxes on equity awards and other			—						(4,096)						—						—						(4,096)
Stock based compensation			—						3,920						—						—						3,920
Dividends declared on common stock, $0.06/share			—						(5,236)						—						—						(5,236)
Net loss			—						—						—						(56,810)						(56,810)
March 31, 2022			$	86					$	907,059					$	(52,436)					$	(224,283)					$	630,426

			Three Months Ended March 31,
			2022						2021
			(in thousands)
Cash flows from operating activities:
Net loss			$	(56,810)					$	(21,322)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			39,777						33,840
Amortization of debt issuance costs			576						1,360
Stock-based compensation expense			3,686						3,779
Deferred income taxes			(2,002)						(376)
Other operating expenses			(910)						—
Derivative activities:
Total losses			132,804						25,774
Cash settlements on derivatives			(32,152)						850
Changes in assets and liabilities:
Increase in accounts receivable			(25,648)						(296)
Decrease (increase) decrease in other assets			9,231						(5,663)
(Decrease) increase in accounts payable and accrued expenses			(14,093)						1,300
(Decrease) in other liabilities			(5,929)						(816)
Net cash provided by operating activities			48,530						38,430
Cash flows from investing activities:
Capital expenditures:
Capital expenditures			(27,620)						(23,569)
Changes in capital expenditures accruals			9,992						3,508
Acquisitions, net of cash received			(18,932)						—
Proceeds from sale of property and equipment and other			—						124
Net cash used in investing activities			(36,560)						(19,937)
Cash flows from financing activities:
Borrowings under 2021 RBL credit facility			107,000						—
Repayments on 2021 RBL credit facility			(107,000)						—
Dividends paid on common stock			(5,197)						(246)
Shares withheld for payment of taxes on equity awards and other			(4,096)						(1,442)
Net cash used in financing activities			(9,293)						(1,688)
Net increase in cash and cash equivalents			2,677						16,805
Cash and cash equivalents:
Beginning			15,283						80,557
Ending			$	17,960					$	97,362

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

“Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation, which is the sole member of each of its three Delaware limited liability company subsidiaries: (1) Berry Petroleum Company, LLC (“Berry LLC”), (2) CJ Berry Well Services Management, LLC (“C&J Management”) and (3) C&J Well Services, LLC (“CJWS”). As the context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its subsidiary, Berry LLC, and as of October 1, 2021 this also includes CJWS and CJ Management.

Nature of Business

We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional oil reserves in the San Joaquin basin of California, with newly acquired well servicing and abandonment capabilities in California. As of October 1, 2021, we have operated in two business segments: (i) development and production (“D&P”) and (ii) well servicing and abandonment. The D&P business segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which now constitutes our well servicing and abandonment segment, also referred to as “CJWS”.

Berry Corp. 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 three wholly owned subsidiaries. Berry LLC owns and operates our oil and gas assets, all of which are located onshore in the United States (the “U.S.”), in California (in the San Joaquin basin), and Utah (in the Uinta basin). We are focused on the development and production of onshore, low geologic risk, long-lived conventional oil reserves. In January 2022, we divested our natural gas properties in the Piceance basin of Colorado.

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, 2021.

New Accounting Standards Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is an update to the lease standard providing an optional transition approach for land easements allowing entities to evaluate only new or modified land easements. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842),

which provided optional transition relief allowing a prospective approach in applying the new rules by not adjusting comparative period financial information for the effects of the new rules and not requiring disclosures for periods before the effective date. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers. During the second quarter of 2020, this adoption date was further delayed by FASB until fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We adopted these rules in the first quarter of 2022 prospectively.

The following table summarizes our outstanding debt:

			March 31, 2022						December 31, 2021						Interest Rate						Maturity						Security
			(in thousands)
2021 RBL Facility			$	—					$	—					variable rates 5.5% (2022) and 5.3% (2021)						August 26, 2025						Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets
2026 Notes			400,000						400,000						7.0%						February 15, 2026						Unsecured
Long-Term Debt - Principal Amount			400,000						400,000
Less: Debt Issuance Costs			(5,154)						(5,434)
Long-Term Debt, net			$	394,846					$	394,566

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At March 31, 2022 and December 31, 2021, debt issuance costs for the 2021 RBL Facility (as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $4 million and $5 million net of amortization, respectively. At March 31, 2022 and December 31, 2021, 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 was approximately $5 million.

For each of the three month periods ended March 31, 2022 and 2021, the amortization expense for the 2021 RBL Facility, the 2017 RBL Facility (as defined below) and the 2026 Notes, combined, was approximately $1 million. The amortization of debt issuance costs is presented 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 2021 RBL Facility approximates fair value because the interest rates are variable and reflect market rates. The fair value of the 2026 Notes was approximately $398 million and $400 million at March 31, 2022 and December 31, 2021, respectively.

2021 RBL Facility

On August 26, 2021, Berry Corp, as a guarantor, together with Berry LLC, as the borrower, entered into a credit agreement that provided for a revolving loan with up to $500 million of commitment, subject to a reserve borrowing base (as amended by the First Amendment and the Second Amendment, each as defined below, the “2021 RBL Facility”). Our initial borrowing base was $200 million. The 2021 RBL Facility provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $20 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the 2021 RBL Facility on a dollar for dollar basis. The 2021 RBL Facility matures on August 26, 2025, unless terminated earlier in accordance with the 2021 RBL Facility terms. Borrowing base redeterminations generally become effective each May and November, although the

borrower and the lenders may each make one interim redetermination between scheduled redeterminations. In December 2021, we completed the first scheduled semi-annual borrowing base redetermination and entered into that certain First Amendment to Credit Agreement (the “First Amendment”), which resulted in a reaffirmed borrowing base at $200 million and changes to the hedging covenants in respect of the exclusion of short puts or similar derivatives in the calculation of minimum and maximum hedging requirements. In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower, entered into that certain Second Amendment to Credit Agreement and Limited Consent and Waiver (the “Second Amendment”) pursuant to which, among other things, the requisite lenders under the 2021 RBL Facility (i) consented to certain dividends and distributions and to certain investments made by Berry LLC in C&J Well Services, LLC and/or CJ Berry Well Services Management, LLC, in each case, as further described therein, (ii) waived certain minimum hedging requirements for the time periods described therein, (iii) waived any breach, default or event of default which may have arisen as a result of any of the foregoing, (iv) amended the restricted payments covenant to give us additional flexibility to make restricted payments, subject to satisfaction of certain leverage and availability conditions and other conditions described below and in the Second Amendment and (v) amended the minimum hedging covenant to not, until October 1, 2022, require hedges for any full calendar month from and after January 1, 2025, as further described in the Second Amendment.

2017 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 (“2017 RBL Facility”). In April 2021, we completed our scheduled semi-annual borrowing base redetermination under our 2017 RBL Facility, which resulted in a reaffirmed borrowing base at $200 million. On August 26, 2021, we cancelled the 2017 RBL Facility agreement. There were no borrowings outstanding at the time of cancellation.

Debt 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 do not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any notes under this program.

We utilize derivatives, such as swaps, puts, calls and collars, 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. In addition to the hedging requirements of the 2021 RBL Facility, 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 fixed dividends as applicable, with the oil and gas sales hedges for a period of up to three 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 three years. We have also entered into Utah gas transportation contracts to help reduce the price fluctuation exposure, however these do not qualify as hedges. 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. We had no such transactions in the periods presented.

For fixed-price oil and gas sales swaps, we are the seller, so we make settlement payments for prices above the indicated weighted-average price per barrel and per mmbtu, respectively, and receive settlement payments for prices below the indicated weighted-average price per barrel and per mmbtu, respectively.

For our long put spreads, in addition to any deferred premium payments, we would receive settlement payments for prices below the indicated highest price of the long put with the maximum payment received per barrel equal to the difference between the indicated prices of the long and short put. No payment would be made or received for prices above the highest indicated price of the long put. The short put spreads offset the long put spreads.

For our purchased oil puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel of Brent. For some of our options we paid or received a premium at the time the positions were created and for others, the premium payment or receipt is deferred until the time of settlement. As of March 31, 2022 we have net payable deferred premiums of approximately $14 million, which is reflected in the mark-to-market valuation and will be payable beginning in 2022 through 2024, in approximately the same amount each year.

For our sold oil calls, we would make settlement payments for prices above the indicated weighted-average price. No payment would be due for prices below the indicated weighted-average price.

For our purchased gas calls, we would receive settlement payments for prices above the indicated weighted-average price. No payment would be received for prices below the indicated weighted-average price.

For our sold oil and gas puts, we would make settlement payments for prices below the indicated weighted-average price. No payment would be due for prices above the indicated weighted-average price.

We use oil and gas production hedges to protect our sales against decreases in oil and gas prices. We also use natural gas purchase hedges 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, 2022, we had the following hedges for our crude oil production and natural gas purchases.

									Q2 2022						Q3 2022						Q4 2022						FY 2023						FY 2024
Brent - Crude Oil production
Swaps
Hedged volume (bbls)									1,299,500						1,288,000						1,196,000						3,420,750						1,917,000
Weighted-average price ($/bbl)									$	75.92					$	75.97					$	74.05					$	72.98					$	75.52
Put Spreads
Long $50/$40 Put Spread hedged volume (bbls)									409,500						414,000						414,000						2,555,000						1,647,000
Short $50/$40 Put Spread hedged volume (bbls)									45,500						46,000						46,000						365,000						366,000
Producer Collars hedged volume (bbls)									—						—						—						1,460,000						1,098,000
Weighted-average price ($/bbl)									—						—						—						$40.00/$106.00						$40.00/$105.00
Henry Hub - Natural Gas purchases
Consumer Collars
Hedged volume (mmbtu)									2,730,000						2,760,000						2,760,000						10,950,000						9,150,000
Weighted-average price ($/mmbtu)									$4.00/$2.75						$4.00/$2.75						$4.00/$2.75						$4.00/$2.75						$4.00/$2.75

In April we added consumer collars (Henry Hub) of 300,000 mmbtu for the second quarter of 2022 and 1,840,000 mmbtu for the second half of 2022 at $4.00/$2.75. We terminated consumer collars (Henry Hub) of 5,520,000 mmbtu for 2023 and 9,150,000 mmbtu for 2024 at $4.00/$2.75, resulting in a net cash impact of less than $1 million.

We sold fixed price oil swaps (Brent) of 245,000 bbls at $102.36 for May 2022 through December 2022 and 12,778 bbls at $93.10 for 2023.

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, 2022 and December 31, 2021:

			March 31, 2022
			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 Contracts			Current assets						$	23,513					$	(23,513)					$	—
Commodity Contracts			Non-current assets						43,081						(43,081)						—
Liabilities:
Commodity Contracts			Current liabilities						(115,985)						23,513						(92,472)
Commodity Contracts			Non-current liabilities						(99,289)						43,081						(56,208)
Total derivatives									$	(148,680)					$	—					$	(148,680)

			December 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 Contracts			Current assets						$	5,360					$	(5,360)					$	—
Commodity Contracts			Non-current assets						29,828						(28,758)						1,070
Liabilities:
Commodity Contracts			Current liabilities						(34,985)						5,360						(29,625)
Commodity Contracts			Non-current liabilities						(47,335)						28,758						(18,577)
Total derivatives									$	(47,132)					$	—					$	(47,132)

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 2021 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 A2 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.

In the normal course of business, we, or our subsidiaries, 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, 2022 and December 31, 2021. 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 subsidiaries, 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, 2022, we are not aware of material indemnity claims pending or threatened against us.

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 (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the Exchange Act, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.'s securities between July 26, 2018 and November 3, 2020 (the “Class Period”). In particular, 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 on November 3, 2020.

On January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended 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. The Defendants filed a Motion to Dismiss on January 24, 2022, and the plaintiffs’ filed their opposition on April 11, 2022; Defendants’ reply is due on June 6, 2022.

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.

Cash Dividends

Our Board of Directors approved a regular cash dividend of $0.06 per share on our common stock for the first quarter of 2022, which we paid in April 2022. The Board of Directors approved a $0.06 per share regular cash dividend on our common stock for the second quarter of 2022, which is expected to be paid in July 2022. The Board of Directors approved a $0.13 per share variable dividend on our common stock based on our first quarter results, which is expected to be paid in June 2022.

Stock Repurchase Program

Stock-Based Compensation

In February 2022, the Company granted awards of approximately 1,300,000 shares of restricted stock units (“RSUs”), which will vest annually in equal amounts over three years. In March 2022, the Company granted awards of approximately 611,000 shares performance-based restricted stock units (“PSUs”), which will cliff vest, if at all, at the end of a three year performance period. The RSUs awarded are equity awards as they will be settled in stock. The PSUs awarded are liability awards as they can be settled in cash or stock. The fair value of these awards was approximately $19 million, of which $8 million relates to liability awards, which will be subsequently remeasured at each reporting period.

The RSUs awarded in February 2022 are solely time-based awards. Of the PSUs awarded to certain Berry employees (excluding CJWS employee awards) in March 2022, (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 44 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) 50% of such awards will vest, if at all, based on the consolidated Company's average cash returned on invested capital (“CROIC PSUs”) over the performance period. The PSUs awarded to certain CJWS employees in March 2022 will vest, if at all based on the CJWS average cash returned on invested capital (“ROIC 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 and ROIC PSUs granted.

The fair value of the RSUs was determined using the grant date stock price. The fair value of the CROIC PSUs and ROIC PSUs was determined using the stock price and estimated performance as of the reporting period as the awards are liability awards. 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 as of the reporting period as the awards are liability awards. 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.

Other current assets reported on the condensed consolidated balance sheets included the following:

			March 31, 2022						December 31, 2021
			(in thousands)
Prepaid expenses			$	19,702					$	26,840
Materials and supplies			9,305						9,533
Deposits			3,720						6,415
Oil inventories			2,756						2,933
Other			1,084						225
Total other current assets			$	36,567					$	45,946

Other non-current assets at March 31, 2022 and December 31, 2021, included approximately $4 million and $5 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, 2022						December 31, 2021
			(in thousands)
Accounts payable-trade			$	23,599					$	17,699
Accrued expenses			63,029						62,962
Royalties payable			18,373						24,816
Greenhouse gas liability - current portion			6,972						7,513
Taxes other than income tax liability			11,095						8,273
Accrued interest			3,713						10,736
Dividends payable			4,840						4,800
Asset retirement obligations - current portion			20,000						20,000
Operating lease liability			1,779						—
Other			684						725
Total accounts payable and accrued expenses			$	154,084					$	157,524

The decrease of $1 million in the long-term portion of the asset retirement obligations from $144 million at December 31, 2021 to $143 million at March 31, 2022 was due to $5 million of liabilities settled during the period, and a $1 million reduction related to property sales. These decreases were offset by $3 million of accretion and $3 million of liabilities incurred.

Other non-current liabilities at March 31, 2022 included approximately $17 million of greenhouse gas liability and $7 million of operating lease noncurrent liability. For December 31, 2021, we had $18 million in greenhouse gas liability.

Supplemental Information on the Statement of Operations

For the three months ended March 31, 2022, other operating expenses was $4 million and mainly consisted of over $2 million in royalty audit charges incurred prior to our emergence and restructuring in 2017, and approximately $1 million loss on the divestiture of the Piceance properties. For the three months ended March 31, 2021, other operating expenses was $1 million and mainly consisted of oil tank storage fees.

Supplemental Cash Flow Information

Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:

			Three Months Ended March 31,
			2022						2021
			(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties			$	243					$	1,020
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized			$	14,539					$	14,637

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. Such amounts are immaterial as of March 31, 2022 and December 31, 2021.

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, 2022 and 2021 no incremental RSU or PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if converted” method.

			Three Months Ended March 31,
			2022						2021
			(in thousands except per share amounts)
Basic EPS calculation
Net loss			$	(56,810)					$	(21,322)
Weighted-average shares of common stock outstanding			80,298						80,115
Basic loss per share			$	(0.71)					$	(0.27)
Diluted EPS calculation
Net loss			$	(56,810)					$	(21,322)
Weighted-average shares of common stock outstanding			80,298						80,115
Dilutive effect of potentially dilutive securities(1)			—						—
Weighted-average common shares outstanding - diluted			80,298						80,115
Diluted loss per share			$	(0.71)					$	(0.27)

(1)    We excluded approximately 4.1 million and 2.2 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for the three months ended March 31, 2022 and 2021, because their effect was anti-dilutive.

We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with additional revenue generated from sales of electricity and marketing activities. Effective October 1, 2021, we completed the acquisition of CJWS, a well servicing and abandonment business. Revenue from CJWS is generated from well servicing and abandonment business.

The following table provides disaggregated revenue for the three months ended March 31, 2022 and 2021:

			Three Months Ended March 31,
			2022						2021
			(in thousands)
Oil sales			$	202,724					$	122,359
Natural gas sales			5,982						12,077
Natural gas liquids sales			1,645						829
Service revenue			39,836						—
Electricity sales			5,419						10,069
Marketing revenues			289						2,234
Other revenues			45						137
Revenues from contracts with customers			255,940						147,705
Losses on oil and gas sales derivatives			(161,858)						(53,504)
Total revenues and other			$	94,082					$	94,201

Note 9—Acquisition and Divestiture

Note 10—Segment Information

			Three Months Ended March 31, 2022
			Development & Production						Well Servicing and Abandonment						Corporate/Eliminations						Consolidated Company
			(in thousands)
Revenues - excluding hedges			$	216,104					$	39,836					$	—					$	255,940
Net loss before income taxes			$	(34,291)					$	(284)					$	(25,586)					$	(60,161)
Adjusted EBITDA			$	105,649					$	3,300					$	(13,237)					$	95,712
Capital expenditures			$	26,437					$	628					$	555					$	27,620
Total assets			$	1,471,358					$	73,887					$	(50,518)					$	1,494,727

			Three Months Ended March 31, 2022
			Development & Production						Well Servicing and Abandonment						Corporate/Eliminations						Consolidated Company
			(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net loss			$	(34,291)					$	(284)					$	(22,235)					(56,810)
Add (Subtract):
Interest expense			—						—						7,675						7,675
Income tax benefit			—						—						(3,351)						(3,351)
Depreciation, depletion, and amortization			35,474						3,179						1,124						39,777
Losses on derivatives			132,804						—						—						132,804
Net cash paid for scheduled derivative settlements			(32,152)						—						—						(32,152)
Other operating expenses			3,495						174						100						3,769
Stock compensation expense			319						33						3,450						3,802
Non-recurring costs			—						198						—						198
Adjusted EBITDA			$	105,649					$	3,300					$	(13,237)					$	95,712

In the first quarter of 2021, we adopted ASC 842 using the modified retrospective approach that requires us to determine our lease balances as of the date of adoption. Prior periods continue to be reported under accounting standards in effect for those periods.

The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s balance sheet. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. We have long-term operating leases generally for offices. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rate used for the three months ended March 31, 2022 was 5%.

Leases with an initial term of 12 months or less are not recorded on the balance sheet and the Company recognizes lease expense for these leases on a straight-line basis over the lease term.

The following table presents supplemental interim consolidated balance sheet information related to leases as of March 31, 2022.

			Three Months Ended March 31, 2022						Balance Sheet Classification
			(in thousands)
Leases
Assets
Operating lease assets			$	8,045					Other property and equipment
Operating lease noncurrent assets			526						Other noncurrent assets
Total assets			$	8,571
Liabilities
Operating lease liability			$	1,779					Accounts payable and accrued expenses
Operating lease noncurrent liability			6,792						Other noncurrent liabilities
Total liabilities			$	8,571

						Three Months Ended March 31, 2022
Long-Term and Discount Rate
Weighted-average remaining lease term:
Operating Lease						5.0 years
Weighted-average discount rate:
Operating Lease						5		%

The following table presents a schedule of future minimum lease payments required under all operating lease agreements as of March 31, 2022.

						As of March 31, 2022
						Operating Leases
						(in thousands)
2022						$	1,779
2023						1,903
2024						1,603
2025						1,551
2026						1,555
Thereafter						1,213
Total lease payments						9,604
Less imputed interest						(1,033)
Total lease obligations						8,571
Less current obligations						(1,779)
Long-term lease obligations						$	6,792

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) 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, 2021 (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) for periods prior to October 1, 2021, Berry Corporation (bry), a Delaware corporation (formerly known as Berry Petroleum Corporation,“Berry Corp.”), together with its subsidiary Berry Petroleum, LLC, a Delaware limited liability company (“Berry LLC”); and (ii) for periods on or after October 1, 2021, Berry Corp. together with its subsidiaries, Berry LLC, CJ Berry Well Services Management, LLC, a Delaware limited liability company (“C&J Management”), and C&J Well Services, LLC, a Delaware limited liability company (“C&J Well Services”).

Our Company

We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional oil reserves in the San Joaquin basin of California, with newly acquired well servicing and abandonment capabilities in California. Since October 1, 2021, we have operated in two business segments: (i) development and production (“D&P”) and (ii) well servicing and abandonment. The D&P business segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which now constitutes our well servicing and abandonment segment, also referred to as “CJWS.”

The assets in our D&P business, in the aggregate, are characterized by high oil content, with 100% oil content for our California assets and are in rural areas with low population. 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. The California oil market has primarily Brent-influenced pricing which has recently realized premium pricing to WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin, which has more than 150 years of production history and substantial oil remaining 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. We also have upstream assets in the low-operating cost, oil-rich reservoirs in the Uinta basin of Utah. In January 2022, we divested our natural gas properties in the Piceance basin of Colorado.

CJWS provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services, and water logistics. CJWS’ services include rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic growth opportunity for Berry. CJWS is a synergistic fit with the services required by our oil and gas operations and supports our commitment to be a responsible operator and reduce our emissions, including through the proactive plugging and abandonment of wells. Additionally, CJWS is critical to advancing our strategy to work with the State of California to reduce fugitive emissions - including methane and carbon dioxide - from idle wells. There are approximately 35,000 idle wells estimated to be in California according to third-party sources. We believe that CJWS is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as an orphan well), in addition to helping third-party customers address their idle wells.

Since our Initial Public Offering in 2018, we have demonstrated our commitment to returning a substantial amount of capital to shareholders, delivering $139 million to our shareholders through dividends and share repurchases through April 30, 2022. In 2022, we initiated a new shareholder return model, designed to significantly increase cash returns to our shareholders from our Discretionary Free Cash Flow. We define “Discretionary Free Cash Flow,” which is a non-GAAP financial measure, as cash flow from operations less regular fixed dividends and the capital needed to hold production flat. This supplemental non-GAAP financial measure is used by management, including as described below under “Management’s Discussion and Analysis—How We Plan and Evaluate

Operations,” as well as by external users of our financial statements. Please see “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliation of Discretionary Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. Like our business model, this new shareholder returns model is simple and further demonstrates our commitment to return capital to our shareholders.

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 to fund our operations, optimize capital efficiency, and generate Discretionary Free Cash Flow, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles. “Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less capital expenditures, interest expense and dividends. “Adjusted EBITDA” is also a non-GAAP financial measure defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual and infrequent items. These supplemental non-GAAP financial measures are used by management, including as described below under “Management’s Discussion and Analysis—How We Plan and Evaluate Operations,” as well as by external users of our financial statements. Please see “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliations of Levered Free Cash Flow and Adjusted EBITDA to net cash provided by operating activities and of Adjusted EBITDA to net income (loss), our most directly comparable financial measures calculated and presented in accordance with GAAP.

We have a progressive approach to growing and evolving our businesses 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 the utility of our assets, create value for shareholders, and support environmental goals that align with safe, more efficient and lower emission operations. As part of our commitment to creating long-term value for our stockholders, we are dedicated to conducting our operations in an ethical, safe and responsible manner, to protecting the environment, and to taking care of our people and the communities in which we live and operate. We believe that oil and gas will remain an important part of the energy landscape going forward and our goal is to conduct our business safely and responsibly, while supporting economic stability and social equity through engagement with our stakeholders. We recognize the oil and gas industry’s role in the energy transition and are determined to be part of the solution.

We use the following metrics to manage and assess the performance of our operations: (a) Levered Free Cash Flow; (b) Adjusted EBITDA; (c) Discretionary Free Cash Flow for shareholder returns; (d) operating expenses; (e) environmental, health & safety (“EH&S”) results; (f) general and administrative expenses; (g) production from our D&P business; and (h) the performance of our well servicing and abandonment operations based on activity levels, pricing and relative performance for each service provided.

Levered Free Cash Flow

We use “Levered Free Cash Flow” in planning our capital allocation to sustain production levels and fund internal growth opportunities, as well as determine our strategic hedging needs. We also hedge to meet the hedging requirements of the 2021 RBL Facility. 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.

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of both our D&P business and CJWS. 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 unusual and infrequent items.

Shareholder Returns

Operating Expenses

Overall, operating expense is used by management as a measure of the efficiency with which operations are performing. With respect to our D&P business, 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 and costs of services 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 California steam operations with gas hedges, and more recently agreements to transport fuel gas from the Rockies which have historically been cheaper than the California markets.

Environmental, Health & Safety (EH&S)

Like other companies in the oil and gas industry, the operations of both our D&P business and CJWS are subject to complex federal, state and local laws and regulations that govern health and safety, the release or discharge of materials, and land use or environmental protection that may restrict the use of our properties and operations, increase our costs or lower demand for or restrict the use of our products and services. Please see “Management’s Discussion and Analysis—Regulatory Matters” in this quarterly report as well as “Part I, Item 1 “Regulatory Matters” and Part I, Item 1A. “Risk Factors” in our Annual Report for a discussion of the potential impact that government regulations, including those regarding EH&S matters, may have upon our business, operations, capital expenditures, earnings and competitive position.

As part of our commitment to creating long-term stockholder value, we strive to conduct our operations in an ethical, safe and responsible manner, to protect the environment and to take care of our people and the communities in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the communities in which we operate and our other stakeholders in order to realize the full potential of our resources in a timely fashion that safeguards people and the environment and complies with existing laws and regulations. We monitor our EH&S performance through various measures, and 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.

General and Administrative Expenses

We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities and less than 10% of such costs are capitalized, which we believe 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.

Our operating and financial results, and those of the oil and gas industry as a whole, are heavily influenced by commodity prices. Oil and gas prices, including the differentials between the relevant benchmarks and the prices we receive for our oil and natural gas production in our D&P business, have fluctuated, and may continue to fluctuate, significantly as a result of numerous market-related variables, including global geopolitical and economic conditions. While oil prices have improved in 2022, they still remain volatile.

Our well servicing and abandonment business is dependent on expenditures of oil and gas companies, which tend to fluctuate in line with the volatility of commodity prices. However, because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells historically have been relatively stable and predictable. Additionally, our customers' requirements to plug and abandon wells are largely driven by regulatory requirements which are not dependent on commodity prices.

Brent prices trended higher for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021 and March 31, 2021, reflecting a premium due to the reduction in crude oil supply resulting from sanctions imposed on Russia in response to its large-scale invasion of Ukraine in February 2022 and building on the ongoing recovery in the oil and gas industry in early 2022 due to increasing demand as more states and countries re-open and national and global economies continue to recover from the global COVID-19 pandemic. The demand for oil, while improving as the ability of the global industry to grow supply diminishes and so long as exports from Russia are subject to sanctions, could again decline due to, among other things, uncertainty and volatility arising from the ongoing conflict in Ukraine, release of sanctions on Russia, a widespread resurgence of the COVID-19 outbreak or increasing inflation. Further, the volatility in oil and natural gas prices driven by the conflict between Russia and Ukraine could accelerate the transition away from fossil fuels, resulting in reduced demand over the longer term. The extent to which our operating and financial results of future periods will be adversely impacted by the ongoing conflict in Ukraine, increasing inflation, the 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 conflict in Ukraine, government action with respect to climate change regulation, increasing inflation and international sanctions and speculation as to future actions by OPEC+.

Commodity Pricing and Differentials

Our revenue, costs, profitability, shareholder returns 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 in Part I, Item 1A. “Risk Factors” in our Annual Report.

Average oil prices, as noted below, were higher for the three months ended March 31, 2022 compared to the three months ended December 31, 2021 and March 31, 2021. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics.

In California, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, which was as high as $8.00 per mmbtu and as low as $3.70 per mmbtu during the first quarter of 2022, while we paid an average of $6.30 per mmbtu in this period.

The following table presents the average Brent, WTI, Kern, Delivered, and Henry Hub prices for the three months ended March 31, 2022, December 31, 2021 and March 31, 2021:

			Three Months Ended
			March 31, 2022						December 31, 2021						March 31, 2021
Oil (bbl) – Brent			$	97.90					$	79.66					$	61.32
Oil (bbl) – WTI			$	94.54					$	76.89					$	57.82
Natural gas (mmbtu) – Kern, Delivered			$	4.83					$	5.65					$	7.99
Natural gas (mmbtu) – Henry Hub			$	4.67					$	4.75					$	3.50

As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 70% of the state’s demand from OPEC+ countries and other waterborne sources. 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. In recent history, the California gas markets have generally had higher gas prices than the Rockies and the rest of the United States. 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. In addition, we have entered into pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that help 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 two of our cogeneration facilities under long-term contracts with terms ending in July 2022 through December 2026. The most significant input and cost of the cogeneration facilities is natural gas. We generally receive significantly more revenue from these cogeneration facilities in the summer months, most notably in June through September, due to negotiated capacity payments we receive.

Regulatory Matters

Like other companies in the oil and gas industry, both our D&P business and CJWS are subject to complex and stringent federal, state, and local laws and regulations, and California, where most of our operations and assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations. A combination of federal, state and local laws and regulations govern most aspects of our activities in California. Collectively, the effect of the existing laws and regulations is to potentially limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, and reduce the amount of oil and natural gas that we can produce from our wells below levels that would otherwise be possible. Additionally, the regulatory burden on the industry increases our costs and consequently may have an adverse effect upon operations, capital expenditures, earnings and our competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and future prospects. For additional information about the potential impact that government regulations, including those regarding environmental matters, may have upon our business, operations, capital expenditures, earnings and competitive position, please see Part I, Item 1 “Regulatory Matters,” as well as Part I, Item 1A. “Risk Factors” in our Annual Report.

Our oil and gas operations in California are subject to compliance with the California Environmental Quality Act (“CEQA”), and we cannot receive certain permits and other approvals required for our operations until we have demonstrated compliance with CEQA. There have been a number of developments at both the California state and local levels that have resulted in delays in the issuance of new drilling permits for oil and gas activities in Kern County where all of our California assets are located, as well as a more time- and cost- intensive permitting process. Most notably, in Kern County, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (an “EIR”) covering oil and gas operations in Kern County (“Kern County EIR”). In 2020, a lawsuit was filed challenging the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County made certain revisions to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County elected to prepare a supplemental EIR which was approved by the Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs, a Kern County Superior Court judge suspended use of the Kern County EIR as supplemented, stopping the issuance of new oil and gas permits by Kern County (the “Kern County Permit Suspension”) in October 2021, pending a determination by the Kern County Superior Court that the Kern County EIR complied with the CEQA requirements. A hearing on the challenge to the EIR is scheduled in Kern County Superior Court for May 26, 2022. We cannot predict the outcome of this hearing or whether it will result in the imposition of more onerous permit requirements or other requirements or restrictions on land use and exploration and production activities.

Importantly, neither the Kern County Ruling nor the Kern County Permit Suspension invalidated existing permits and our plans and operations have not been materially impacted to date. Until Kern County is able to resolve the challenges regarding the sufficiency of the Kern County EIR and resume the ability to issue permits, our ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating to CalGEM compliance with CEQA. Demonstrating CEQA compliance without being able to reference the Kern County EIR or another CEQA-compliant EIR is a more technically, time and cost intensive process and may, among other things, require that we conduct an environmental impact review. As a result, we together with other Kern County operators

have experienced delays in the issuance of permits for new wells by CalGEM, as well as a more time- and cost- intensive permitting process. We have, however, received a number of permits to drill new wells in areas covered by a previously conducted CEQA analysis. We believe that we have sufficient permit inventory (that is, permits in hand) to support our drilling plans for new wells into June 2022, and we have submitted permit applications to facilitate our full 2022 drilling plans for new wells. We have not experienced delays in the issuance of permits for the workover of existing wells.

Approximately 6% of our current 2022 production plans is expected to come from the drilling of new wells, which requires the issuance of new permits and extensive environmental review. Approximately 4% of our 2022 production is expected to come from the workover of existing wells, for which we have continued to receive permits and the environmental review is expedited because the well already exists. Our existing producing wells are expected to contribute the other 90%, what we call our base production. Our drilling plans for the remainder of the year, and therefore our current 2022 production goals, may be impacted by our ability to timely obtain the required permits and approvals to support those planned activities, particularly if there are further delays in or new restrictions imposed upon the issuance or renewal of permits and approvals required for oil and gas activities in Kern County. If we are unable to obtain the permits required to support our current 2022 drilling plans, we may modify our drilling plans and production goals, and reduce our planned capital expenditures or deploy that capital to other activities.

Seasonality

Seasonal weather conditions can impact our drilling, production and well servicing 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, especially in Utah, 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. For example, natural gas prices increased significantly in the first quarter of 2022 reflecting a premium driven by European instability which brought new demand for domestic production as a way to replace natural gas previously produced by Russia, as well as lower storage levels.We purchase significantly more gas than we sell to generate steam and electricity in our cogeneration facilities for our production activities in our D&P business. 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 in 2021 we entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our operations in California to help limit our exposure to fuel gas purchase price fluctuations.

For the three months ended March 31, 2022, our consolidated capital expenditures were approximately $28 million, on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement spending. Approximately 53% and 35% of capital expenditures for the three months ended March 31, 2022 was directed to California oil and Utah operations, respectively.

Our 2022 capital expenditure budget for D&P operations and corporate activities is approximately $125 to $135 million, excluding $8 million for C&J Well Services, which we expect will keep our annual production flat. We currently anticipate oil production will be approximately 92% of total production volume in 2022, compared to 88% in 2021. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2022 capital development programs with cash flow from operations. The execution of these plans requires that we timely obtain certain regulatory permits and approvals, which we may not be able to obtain on a timely basis or at all.

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 2022, we plan to spend approximately $21 million to $24 million on plugging and abandonment activities, including 280 to 320 wells and satisfying our annual obligations under the California Idle Well Management Program. We spent approximately $5 million for plugging and abandonment activities in the first quarter of 2022. Our well servicing and abandonment segment expects to plug and abandon approximately 2,000 wells for their third party customers in 2022, helping to safely address the environmental hazards and others risk from California’s number of idle wells.

The following table shows a summary by area of our selected historical financial and operating information for our development and production operations for the periods indicated.

			California (San Joaquin and Ventura basins)(3)
			Three Months Ended
			March 31, 2022						December 31, 2021						March 31, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales			$	186,252					$	158,317					$	113,177
Operating income(1)			$	60,162					$	17,217					$	18,965
Depreciation, depletion, and amortization (DD&A)			$	35,786					$	35,647					$	32,896
Average daily production (mboe/d)			22.2						22.7						21.9
Production (oil % of total)			100		%				100		%				100		%
Realized sales prices:
Oil (per bbl)			$	93.16					$	75.90					$	57.34
NGLs (per bbl)			$	—					$	—					$	—
Gas (per mcf)			$	—					$	—					$	—
Capital expenditures(2)			$	14,622					$	22,596					$	22,760

			Utah (Uinta basin)																					Colorado (Piceance basin)(4)
			Three Months Ended																					Three Months Ended
			March 31, 2022						December 31, 2021						March 31, 2021									March 31, 2022						December 31, 2021						March 31, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales			$	23,038					$	19,762					$	15,889								$	1,056					$	3,294					$	6,194
Operating income(1)			$	11,173					$	8,713					$	7,433								$	610					$	3,050					$	5,039
Depreciation, depletion, and amortization (DD&A)			$	803					$	597					$	554								$	9					$	38					$	38
Average daily production (mboe/d)			4.1						4.2						4.0									0.4						1.0						1.2
Production (oil % of total)			53		%				51		%				49		%							—		%				1		%				2		%
Realized sales prices:
Oil (per bbl)			$	83.02					$	66.56					$	52.08								$	89.41					$	84.38					$	25.80
NGLs (per bbl)			$	47.03					$	47.45					$	26.81								$	—					$	—					$	—
Gas (per mcf)			$	5.93					$	5.63					$	6.65								$	5.12					$	5.54					$	9.83
Capital expenditures(2)			$	9,752					$	1,007					$	392								$	—					$	—					$	1

(1)    Operating income (loss) includes oil, natural gas and NGL sales, marketing revenues, other revenues, 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.

(3)    Our Placerita properties, in the Ventura basin, were divested in October 2021.

(4)    Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.

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, 2022						December 31, 2021						March 31, 2021
Average daily production:(1)
Oil (mbbl/d)			24.4						24.8						23.9
Natural Gas (mmcf/d)			11.5						16.4						16.9
NGL (mbbl/d)			0.4						0.4						0.3
Total (mboe/d)(2)			26.7						27.9						27.1
Total Production:
Oil (mbbl)			2,198						2,281						2,151
Natural gas (mmcf)			1,037						1,496						1,517
NGLs (mbbl)			35						36						31
Total (mboe)(2)			2,406						2,566						2,435
Weighted-average realized sales prices:
Oil without hedges ($/bbl)			$	92.25					$	75.11					$	56.89
Effects of scheduled derivative settlements ($/bbl)			$	(15.38)					$	(20.50)					$	(12.08)
Oil with hedges ($/bbl)			$	76.87					$	54.61					$	44.81
Natural gas ($/mcf)			$	5.77					$	5.60					$	7.96
NGL ($/bbl)			$	47.03					$	47.45					$	26.81
Average Benchmark prices:
Oil (bbl) – Brent			$	97.90					$	79.66					$	61.32
Oil (bbl) – WTI			$	94.54					$	76.89					$	57.82
Natural gas (mmbtu) – Kern, Delivered(3)			$	4.83					$	5.65					$	7.99
Natural gas (mmbtu) – Henry Hub(4)			$	4.67					$	4.75					$	3.50