BRY

12/312022Q2false0001705873http://fasb.org/us-gaap/2022#OtherAssetsNoncurrenthttp://fasb.org/us-gaap/2022#AccountsPayableAndAccruedLiabilitiesCurrenthttp://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent00017058732022-01-012022-06-3000017058732022-07-31xbrli:shares00017058732022-06-30iso4217:USD00017058732021-12-31iso4217:USDxbrli:shares0001705873us-gaap:OilAndGasMember2022-04-012022-06-300001705873us-gaap:OilAndGasMember2021-04-012021-06-300001705873us-gaap:OilAndGasMember2022-01-012022-06-300001705873us-gaap:OilAndGasMember2021-01-012021-06-300001705873us-gaap:ServiceOtherMember2022-04-012022-06-300001705873us-gaap:ServiceOtherMember2021-04-012021-06-300001705873us-gaap:ServiceOtherMember2022-01-012022-06-300001705873us-gaap:ServiceOtherMember2021-01-012021-06-300001705873us-gaap:ElectricityMember2022-04-012022-06-300001705873us-gaap:ElectricityMember2021-04-012021-06-300001705873us-gaap:ElectricityMember2022-01-012022-06-300001705873us-gaap:ElectricityMember2021-01-012021-06-3000017058732022-04-012022-06-3000017058732021-04-012021-06-3000017058732021-01-012021-06-300001705873us-gaap:AdvertisingMember2022-04-012022-06-300001705873us-gaap:AdvertisingMember2021-04-012021-06-300001705873us-gaap:AdvertisingMember2022-01-012022-06-300001705873us-gaap:AdvertisingMember2021-01-012021-06-300001705873us-gaap:ProductAndServiceOtherMember2022-04-012022-06-300001705873us-gaap:ProductAndServiceOtherMember2021-04-012021-06-300001705873us-gaap:ProductAndServiceOtherMember2022-01-012022-06-300001705873us-gaap:ProductAndServiceOtherMember2021-01-012021-06-300001705873us-gaap:CommonStockMember2020-12-310001705873us-gaap:AdditionalPaidInCapitalMember2020-12-310001705873us-gaap:TreasuryStockMember2020-12-310001705873us-gaap:RetainedEarningsMember2020-12-3100017058732020-12-310001705873us-gaap:AdditionalPaidInCapitalMember2021-01-012021-03-3100017058732021-01-012021-03-310001705873us-gaap:CommonStockMember2021-01-012021-03-310001705873us-gaap:RetainedEarningsMember2021-01-012021-03-310001705873us-gaap:CommonStockMember2021-03-310001705873us-gaap:AdditionalPaidInCapitalMember2021-03-310001705873us-gaap:TreasuryStockMember2021-03-310001705873us-gaap:RetainedEarningsMember2021-03-3100017058732021-03-310001705873us-gaap:AdditionalPaidInCapitalMember2021-04-012021-06-300001705873us-gaap:RetainedEarningsMember2021-04-012021-06-300001705873us-gaap:CommonStockMember2021-06-300001705873us-gaap:AdditionalPaidInCapitalMember2021-06-300001705873us-gaap:TreasuryStockMember2021-06-300001705873us-gaap:RetainedEarningsMember2021-06-3000017058732021-06-300001705873us-gaap:CommonStockMember2021-12-310001705873us-gaap:AdditionalPaidInCapitalMember2021-12-310001705873us-gaap:TreasuryStockMember2021-12-310001705873us-gaap:RetainedEarningsMember2021-12-310001705873us-gaap:AdditionalPaidInCapitalMember2022-01-012022-03-3100017058732022-01-012022-03-310001705873us-gaap:RetainedEarningsMember2022-01-012022-03-310001705873us-gaap:CommonStockMember2022-03-310001705873us-gaap:AdditionalPaidInCapitalMember2022-03-310001705873us-gaap:TreasuryStockMember2022-03-310001705873us-gaap:RetainedEarningsMember2022-03-3100017058732022-03-310001705873us-gaap:AdditionalPaidInCapitalMember2022-04-012022-06-300001705873us-gaap:TreasuryStockMember2022-04-012022-06-300001705873us-gaap:RetainedEarningsMember2022-04-012022-06-300001705873us-gaap:CommonStockMember2022-06-300001705873us-gaap:AdditionalPaidInCapitalMember2022-06-300001705873us-gaap:TreasuryStockMember2022-06-300001705873us-gaap:RetainedEarningsMember2022-06-30bry:subsidiary00017058732021-10-012022-06-30bry:segment0001705873bry:RBLFacility2021Memberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2022-06-300001705873bry:RBLFacility2021Memberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-12-31xbrli:pure0001705873us-gaap:LineOfCreditMemberbry:RBLFacility2021Member2021-12-310001705873bry:SeniorUnsecuredNotesDue2026Memberus-gaap:UnsecuredDebtMember2022-06-300001705873bry:SeniorUnsecuredNotesDue2026Memberus-gaap:UnsecuredDebtMember2021-12-310001705873bry:RBLFacilityMemberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2022-06-300001705873bry:RBLFacilityMemberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-12-310001705873us-gaap:InterestExpenseMember2022-04-012022-06-300001705873us-gaap:InterestExpenseMember2021-04-012021-06-300001705873us-gaap:InterestExpenseMember2022-01-012022-06-300001705873us-gaap:InterestExpenseMember2021-01-012021-06-300001705873bry:RBLFacility2021Memberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-08-260001705873us-gaap:LetterOfCreditMemberbry:RBLFacility2021Memberus-gaap:LineOfCreditMember2021-08-260001705873bry:RBLFacility2021Memberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2022-05-310001705873bry:RBLFacility2021Memberus-gaap:RevolvingCreditFacilityMember2022-05-310001705873bry:RBLFacility2021Memberus-gaap:RevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2022-05-012022-05-310001705873bry:RBLFacility2021Membersrt:MinimumMemberus-gaap:RevolvingCreditFacilityMemberus-gaap:SecuredOvernightFinancingRateSofrOvernightIndexSwapRateMember2022-05-012022-05-310001705873bry:RBLFacility2021Memberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-08-262021-08-260001705873bry:RBLFacility2021Membersrt:MinimumMemberus-gaap:BaseRateMemberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-08-262021-08-260001705873srt:MaximumMemberbry:RBLFacility2021Memberus-gaap:BaseRateMemberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-08-262021-08-260001705873bry:RBLFacility2021Memberbry:BenchmarkRateMembersrt:MinimumMemberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-08-262021-08-260001705873srt:MaximumMemberbry:RBLFacility2021Memberbry:BenchmarkRateMemberus-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMember2021-08-262021-08-260001705873us-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMemberbry:RBLFacility2017Member2017-07-310001705873us-gaap:LineOfCreditMemberus-gaap:RevolvingCreditFacilityMemberbry:RBLFacility2017Member2021-08-2600017058732020-02-290001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2022-07-012022-09-30utr:bbl0001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2022-10-012022-12-310001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2023-01-012023-12-310001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2024-01-012024-12-310001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2025-01-012025-12-310001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2022-09-30iso4217:USDutr:bbl0001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2022-12-310001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2023-12-310001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2024-12-310001705873srt:ScenarioForecastMemberbry:BrentSwapsMember2025-12-310001705873bry:PutSpreadMembersrt:MaximumMember2022-06-300001705873bry:PutSpreadMembersrt:MinimumMember2022-06-300001705873bry:PutSpreadLongMembersrt:ScenarioForecastMember2022-07-012022-09-300001705873bry:PutSpreadLongMembersrt:ScenarioForecastMember2022-10-012022-12-310001705873bry:PutSpreadLongMembersrt:ScenarioForecastMember2023-01-012023-12-310001705873bry:PutSpreadLongMembersrt:ScenarioForecastMember2024-01-012024-12-310001705873bry:PutSpreadLongMembersrt:ScenarioForecastMember2025-01-012025-12-310001705873bry:PutSpreadShortMembersrt:ScenarioForecastMember2022-07-012022-09-300001705873bry:PutSpreadShortMembersrt:ScenarioForecastMember2022-10-012022-12-310001705873bry:PutSpreadShortMembersrt:ScenarioForecastMember2023-01-012023-12-310001705873bry:PutSpreadShortMembersrt:ScenarioForecastMember2024-01-012024-12-310001705873bry:PutSpreadShortMembersrt:ScenarioForecastMember2025-01-012025-12-310001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2022-07-012022-09-300001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2022-10-012022-12-310001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2023-01-012023-12-310001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2024-01-012024-12-310001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2025-01-012025-12-310001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2022-09-300001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2022-12-310001705873bry:ProducerCollarsMembersrt:MinimumMembersrt:ScenarioForecastMember2023-12-310001705873srt:MaximumMemberbry:ProducerCollarsMembersrt:ScenarioForecastMember2023-12-310001705873bry:ProducerCollarsMembersrt:MinimumMembersrt:ScenarioForecastMember2024-12-310001705873srt:MaximumMemberbry:ProducerCollarsMembersrt:ScenarioForecastMember2024-12-310001705873bry:ProducerCollarsMembersrt:ScenarioForecastMember2025-12-310001705873bry:ConsumerCollarsMembersrt:ScenarioForecastMember2022-07-012022-09-30utr:MMBTU0001705873bry:ConsumerCollarsMembersrt:ScenarioForecastMember2022-10-012022-12-310001705873bry:ConsumerCollarsMembersrt:ScenarioForecastMember2023-01-012023-12-310001705873bry:ConsumerCollarsMembersrt:ScenarioForecastMember2024-01-012024-12-310001705873bry:ConsumerCollarsMembersrt:ScenarioForecastMember2025-01-012025-12-310001705873srt:MaximumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2022-09-30iso4217:USDbry:MMBtu0001705873srt:MinimumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2022-09-300001705873srt:MaximumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2022-12-310001705873srt:MinimumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2022-12-310001705873srt:MaximumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2023-12-310001705873srt:MinimumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2023-12-310001705873srt:MaximumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2024-12-310001705873srt:MaximumMemberbry:ConsumerCollarsMembersrt:ScenarioForecastMember2025-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2022-07-012022-09-300001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2022-10-012022-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2023-01-012023-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2024-01-012024-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2025-01-012025-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2022-09-300001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2022-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2023-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2024-12-310001705873bry:NWPLNaturalGasPurchasesSwapsMembersrt:ScenarioForecastMember2025-12-310001705873us-gaap:OtherCurrentAssetsMemberus-gaap:CommodityContractMember2022-06-300001705873us-gaap:OtherNoncurrentAssetsMemberus-gaap:CommodityContractMember2022-06-300001705873us-gaap:OtherCurrentLiabilitiesMemberus-gaap:CommodityContractMember2022-06-300001705873us-gaap:OtherNoncurrentLiabilitiesMemberus-gaap:CommodityContractMember2022-06-300001705873us-gaap:OtherCurrentAssetsMemberus-gaap:CommodityContractMember2021-12-310001705873us-gaap:OtherNoncurrentAssetsMemberus-gaap:CommodityContractMember2021-12-310001705873us-gaap:OtherCurrentLiabilitiesMemberus-gaap:CommodityContractMember2021-12-310001705873us-gaap:OtherNoncurrentLiabilitiesMemberus-gaap:CommodityContractMember2021-12-310001705873bry:CashDividendMember2022-04-012022-04-300001705873bry:CashDividendMemberus-gaap:SubsequentEventMember2022-07-012022-07-310001705873bry:VariableRateDividendMember2022-06-012022-06-300001705873srt:ScenarioForecastMemberbry:CashDividendMemberus-gaap:SubsequentEventMember2022-08-012022-08-310001705873bry:VariableRateDividendMembersrt:ScenarioForecastMemberus-gaap:SubsequentEventMember2022-08-012022-08-310001705873bry:StockRepurchaseProgramMember2022-04-300001705873bry:StockRepurchaseProgramMember2022-06-300001705873us-gaap:RestrictedStockUnitsRSUMember2022-02-012022-02-280001705873us-gaap:PerformanceSharesMember2022-03-012022-03-3100017058732022-03-012022-03-310001705873us-gaap:ShareBasedCompensationAwardTrancheOneMemberus-gaap:PerformanceSharesMember2022-03-012022-03-310001705873us-gaap:ShareBasedCompensationAwardTrancheOneMember2022-02-012022-02-28bry:company0001705873us-gaap:PerformanceSharesMemberus-gaap:ShareBasedCompensationAwardTrancheTwoMember2022-02-012022-02-280001705873us-gaap:PerformanceSharesMember2022-02-012022-02-280001705873srt:MinimumMemberbry:TotalStockholderReturnPerformanceBasedRestrictedStockUnitsGrantedInPeriodMember2022-02-012022-02-280001705873srt:MaximumMemberbry:TotalStockholderReturnPerformanceBasedRestrictedStockUnitsGrantedInPeriodMember2022-02-012022-02-280001705873srt:MinimumMemberbry:TotalCashReturnOnInvestedCapitalPerformanceBasedRestrictedStockUnitsGrantedMember2022-02-012022-02-280001705873srt:MaximumMemberbry:TotalCashReturnOnInvestedCapitalPerformanceBasedRestrictedStockUnitsGrantedMember2022-02-012022-02-280001705873bry:PiceanceBasinMember2022-01-012022-06-300001705873bry:RestrictedStockUnitsRSUsAndPerformanceSharesMember2022-04-012022-06-300001705873bry:RestrictedStockUnitsRSUsAndPerformanceSharesMember2021-01-012021-06-300001705873bry:RestrictedStockUnitsRSUsAndPerformanceSharesMember2022-01-012022-06-300001705873bry:RestrictedStockUnitsRSUsAndPerformanceSharesMember2021-04-012021-06-300001705873srt:OilReservesMember2022-04-012022-06-300001705873srt:OilReservesMember2021-04-012021-06-300001705873srt:OilReservesMember2022-01-012022-06-300001705873srt:OilReservesMember2021-01-012021-06-300001705873us-gaap:NaturalGasMidstreamMember2022-04-012022-06-300001705873us-gaap:NaturalGasMidstreamMember2021-04-012021-06-300001705873us-gaap:NaturalGasMidstreamMember2022-01-012022-06-300001705873us-gaap:NaturalGasMidstreamMember2021-01-012021-06-300001705873srt:NaturalGasLiquidsReservesMember2022-04-012022-06-300001705873srt:NaturalGasLiquidsReservesMember2021-04-012021-06-300001705873srt:NaturalGasLiquidsReservesMember2022-01-012022-06-300001705873srt:NaturalGasLiquidsReservesMember2021-01-012021-06-300001705873bry:PiceanceBasinMember2022-01-012022-01-310001705873bry:AntelopeCreekAcquisitionMember2022-02-012022-02-280001705873bry:AntelopeCreekAcquisitionMember2022-02-28utr:Boe00017058732021-10-012021-10-0100017058732021-01-012021-09-300001705873us-gaap:OperatingSegmentsMemberbry:DevelopmentAndProductionMember2022-04-012022-06-300001705873us-gaap:OperatingSegmentsMemberbry:WellServicingAndAbandonmentMember2022-04-012022-06-300001705873bry:CorporateAndEliminationsMember2022-04-012022-06-300001705873us-gaap:OperatingSegmentsMemberbry:DevelopmentAndProductionMember2022-06-300001705873us-gaap:OperatingSegmentsMemberbry:WellServicingAndAbandonmentMember2022-06-300001705873bry:CorporateAndEliminationsMember2022-06-300001705873us-gaap:OperatingSegmentsMemberbry:DevelopmentAndProductionMember2022-01-012022-06-300001705873us-gaap:OperatingSegmentsMemberbry:WellServicingAndAbandonmentMember2022-01-012022-06-300001705873bry:CorporateAndEliminationsMember2022-01-012022-06-30

☒						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			21
Item 3.			Quantitative and Qualitative Disclosures About Market Risk			62
Item 4.			Controls and Procedures			62
Part II – Other Information
Item 1.			Legal Proceedings			63
Item 1A.			Risk Factors			63
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities			64
Item 6.			Exhibits			65
			Glossary of Terms			66
			Signatures			74

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)

			June 30, 2022						December 31, 2021
			(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents			$	52,495					$	15,283
Accounts receivable, net of allowance for doubtful accounts of $866 at June 30, 2022 and $866 at December 31, 2021			117,281						86,269
Other current assets			35,122						45,946
Total current assets			204,898						147,498
Noncurrent assets:
Oil and natural gas properties			1,618,258						1,537,894
Accumulated depletion and amortization			(402,640)						(340,328)
Total oil and natural gas properties, net			1,215,618						1,197,566
Other property and equipment			144,917						140,710
Accumulated depreciation			(46,608)						(36,927)
Total other property and equipment, net			98,309						103,783
Derivative instruments			—						1,070
Other noncurrent assets			11,560						6,562
Total assets			$	1,530,385					$	1,456,479
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses			$	160,683					$	157,524
Derivative instruments			101,063						29,625
Total current liabilities			261,746						187,149
Noncurrent liabilities:
Long-term debt			395,135						394,566
Derivative instruments			59,604						18,577
Deferred income taxes			1,322						1,831
Asset retirement obligations			139,956						143,926
Other noncurrent liabilities			31,853						17,782
Commitments and Contingencies - Note 4
Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 86,343,622 and 85,590,417 shares issued; and 78,760,354 and 80,007,149 shares outstanding, at June 30, 2022 and December 31, 2021, respectively)			86						86
Additional paid-in-capital			896,808						912,471
Treasury stock, at cost (7,583,268 and 5,583,268 shares at June 30, 2022 and December 31, 2021, respectively)			(75,196)						(52,436)
Retained deficit			(180,929)						(167,473)
Total stockholders' equity			640,769						692,648
Total liabilities and stockholders' equity			$	1,530,385					$	1,456,479

			Three Months Ended June 30,												Six Months Ended June 30,
			2022						2021						2022						2021
			(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales			$	240,071					$	147,775					$	450,422					$	283,040
Services revenue			46,178						—						86,014						—
Electricity sales			7,419						6,888						12,838						16,957
Losses on oil and gas sales derivatives			(40,658)						(55,653)						(202,516)						(109,157)
Marketing revenues			—						121						289						2,355
Other revenues			120						118						165						255
Total revenues and other			253,130						99,249						347,212						193,450
Expenses and other:
Lease operating expenses			72,455						45,543						135,579						107,827
Costs of services			36,709						—						70,181						—
Electricity generation expenses			6,122						4,712						10,585						12,360
Transportation expenses			1,108						1,757						2,266						3,333
Marketing expenses			—						44						299						2,271
General and administrative expenses			23,183						16,065						46,125						33,135
Depreciation, depletion, and amortization			38,055						35,850						77,832						69,690
Taxes, other than income taxes			11,214						11,603						17,819						21,160
Losses (gains) on natural gas purchase derivatives			10,661						(11,639)						(18,393)						(39,369)
Other operating expenses			353						42						4,122						841
Total expenses and other			199,860						103,977						346,415						211,248
Other (expenses) income:
Interest expense			(7,729)						(8,217)						(15,404)						(16,702)
Other, net			(42)						(8)						(55)						(151)
Total other (expenses) income			(7,771)						(8,225)						(15,459)						(16,853)
Income (loss) before income taxes			45,499						(12,953)						(14,662)						(34,651)
Income tax expense (benefit)			2,145						(72)						(1,206)						(448)
Net income (loss)			$	43,354					$	(12,881)					$	(13,456)					$	(34,203)
Net income (loss) per share:
Basic			$	0.54					$	(0.16)					$	(0.17)					$	(0.43)
Diluted			$	0.52					$	(0.16)					$	(0.17)					$	(0.43)

			Six-Month Period Ended June 30, 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
Shares withheld for payment of taxes on equity awards and other			—						(78)						—						—						(78)
Stock based compensation			—						3,042						—						—						3,042
Dividends declared on common stock, $0.04/share			—						(3,219)						—						—						(3,219)
Net loss			—						—						—						(12,881)						(12,881)
June 30, 2021			$	86					$	914,701					$	(49,995)					$	(186,134)					$	678,658

			Six-Month Period Ended June 30, 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
Shares withheld for payment of taxes on equity awards and other			—						(6)						—						—						(6)
Stock based compensation			—						4,720						—						—						4,720
Purchases of treasury stock			—						—						(22,760)						—						(22,760)
Dividends declared on common stock, $0.19/share			—						(14,965)						—						—						(14,965)
Net income			—						—						—						43,354						43,354
June 30, 2022			$	86					$	896,808					$	(75,196)					$	(180,929)					$	640,769

			Six Months Ended June 30,
			2022						2021
			(in thousands)
Cash flows from operating activities:
Net loss			$	(13,456)					$	(34,203)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			77,832						69,690
Amortization of debt issuance costs			971						2,728
Stock-based compensation expense			8,222						6,639
Deferred income taxes			(509)						(473)
Decrease in allowance for doubtful accounts			—						(500)
Other operating (income) expenses			(187)						142
Derivative activities:
Total losses			184,123						69,788
Cash settlements on derivatives			(69,780)						(36,581)
Changes in assets and liabilities:
Increase in accounts receivable			(30,990)						(11,189)
Decrease (increase) decrease in other assets			3,526						(7,490)
Increase in accounts payable and accrued expenses			1,728						3,406
Decrease in other liabilities			(1,708)						(2,098)
Net cash provided by operating activities			159,772						59,859
Cash flows from investing activities:
Capital expenditures:
Capital expenditures			(61,706)						(67,030)
Changes in capital expenditures accruals			5,363						6,934
Acquisitions, net of cash received			(19,080)						(825)
Proceeds from sale of property and equipment and other			—						409
Net cash used in investing activities			(75,423)						(60,512)
Cash flows from financing activities:
Borrowings under 2021 RBL credit facility			192,000						—
Repayments on 2021 RBL credit facility			(192,000)						—
Dividends paid on common stock			(20,275)						(3,466)
Shares withheld for payment of taxes on equity awards and other			(4,102)						(1,520)
Purchase of treasury stock			(22,760)						—
Net cash used in financing activities			(47,137)						(4,986)
Net increase (decrease) in cash and cash equivalents			37,212						(5,639)
Cash and cash equivalents:
Beginning			15,283						80,557
Ending			$	52,495					$	74,918

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 and gas reserves in the San Joaquin basin of California and the Uinta basin of Utah, with 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.

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 (D&P segment). In January 2022, we divested our natural gas properties in the Piceance basin of Colorado. 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”.

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. Securities 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:

			June 30, 2022						December 31, 2021						Interest Rate						Maturity						Security
			(in thousands)
2021 RBL Facility			$	—					$	—					variable rates 6.8% (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			(4,865)						(5,434)
Long-Term Debt, net			$	395,135					$	394,566

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At June 30, 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 June 30, 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 June 30, 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. For each of the six month periods ended June 30, 2022 and 2021, the amortization expense for the 2021 RBL Facility, the 2017 RBL Facility and the 2026 Notes, combined, was approximately $1 million and $3 million, respectively. 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, classified as Level 1, because the interest rates are variable and reflect market rates. The fair value of the 2026 Notes was approximately $389 million and $400 million at June 30, 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, the Second Amendment and the Third 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. In May 2022, we also completed our semi-annual borrowing base redetermination and entered into the Third Amendment to the Credit Agreement (the “Third Amendment”), which among other things (1) increased the borrowing base from $200 million to $250 million; (2) established the Aggregate Elected Commitment Amounts (as defined in the 2021 RBL Facility) at $200 million initially; and (3) converted all outstanding Eurodollar Loans (into Term Benchmark Loans (each as defined in the 2021 RBL Facility) with an initial interest period of one-month’s duration and otherwise give effect to the transition from the London interbank offered rate (“LIBOR”) to the secured overnight financing rate (“SOFR”) by replacing the adjusted LIBOR rate with the term SOFR rate for one, three or six months plus 0.1% (subject to a floor of 0.5%).

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”). On August 26, 2021, we cancelled the 2017 RBL Facility agreement, which had a borrowing base of $200 million and 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 June 30, 2022 we have net payable deferred premiums of approximately $7 million, which is reflected in the mark-to-market valuation and will be payable beginning in 2022 through 2024.

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 June 30, 2022, we had the following hedges for our crude oil production and natural gas purchases.

															Q3 2022						Q4 2022						FY 2023						FY 2024						FY 2025
Brent - Crude Oil production
Swaps
Hedged volume (bbls)															1,380,000						1,288,000						3,433,528						1,917,000						—
Weighted-average price ($/bbl)															$	77.73					$	76.07					$	73.06					$	75.52					$	—
Put Spreads
Long $50/$40 Put Spread hedged volume (bbls)															414,000						414,000						2,555,000						1,647,000						—
Short $50/$40 Put Spread hedged volume (bbls)															46,000						46,000						365,000						366,000						—
Producer Collars																																							—
Hedged volume (bbls)															—						—						1,460,000						1,098,000						—
Weighted-average price ($/bbl)															$	—					$	—					$40.00/$106.00						$40.00/$105.00						$	—
Henry Hub - Natural Gas purchases
Consumer Collars
Hedged volume (mmbtu)															3,680,000						3,680,000						5,430,000						—						—
Weighted-average price ($/mmbtu)															$4.00/$2.75						$4.00/$2.75						$4.00/$2.75						$	—					$	—
NWPL - Natural Gas purchases
Swaps
Hedged volume (mmbtu)															—						1,220,000						12,800,000						7,320,000						6,080,000
Weighted-average price ($/mmbtu)															$	—					$	6.40					$	5.48					$	4.27					$	4.27

Our commodity derivatives are measured at fair value using industry-standard models with various inputs including publicly available underlying commodity prices and forward curves, and all are classified as Level 2 in the required fair value hierarchy for the periods presented. These commodity derivatives are subject to counterparty netting. The following tables present the fair values (gross and net) of our outstanding derivatives as of June 30, 2022 and December 31, 2021:

			June 30, 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						$	22,794					$	(22,794)					$	—
Commodity Contracts			Non-current assets						27,674						(27,674)						—
Liabilities:
Commodity Contracts			Current liabilities						(123,857)						22,794						(101,063)
Commodity Contracts			Non-current liabilities						(87,278)						27,674						(59,604)
Total derivatives									$	(160,667)					$	—					$	(160,667)

			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 June 30, 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 June 30, 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, for which the Court’s ruling is pending.

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 regular fixed cash dividends of $0.06 per share on our common stock for each of the first two quarters of 2022, which were paid in April and July 2022. The Board of Directors approved a $0.13 per share variable dividend based on our first quarter results, which was paid in June 2022. In July 2022, the Board of Directors approved a $0.06 per share regular fixed cash dividend, as well as a variable dividend of $0.56 based on the second quarter results, each of which is expected to be paid in August 2022.

Stock Repurchase Program

The Company repurchased 2,000,000 shares during the three months ended June 30, 2022 for approximately $23 million. As of June 30, 2022, the Company had repurchased a total of 7,528,704 shares under the stock repurchase program for approximately $75 million in aggregate. As previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company intends to allocate a portion of Discretionary Free Cash Flow to opportunistic share repurchases.

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 were accounted for as liability awards as of March 31, 2022, but converted to equity awards during the second quarter of 2022. The accounting of the awards was converted as a result of the 2022 Omnibus Incentive Plan (the “2022 Plan”) being approved by the stockholders in May 2022. The fair value of these awards was approximately $19 million on the date the 2022 Plan was approved and this will be the value of these awards through the date of their vesting.

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:

			June 30, 2022						December 31, 2021
			(in thousands)
Prepaid expenses			$	19,822					$	26,840
Materials and supplies			8,600						9,533
Deposits			3,773						6,415
Oil inventories			2,702						2,933
Other			225						225
Total other current assets			$	35,122					$	45,946

Other non-current assets at June 30, 2022 included approximately $7 million of operating lease right-of-use assets, net of amortization and $4 million of deferred financing costs, net of amortization. At December 31, 2021 other non-current assets included approximately $5 million of deferred financing costs, net of amortization.

Accounts payable and accrued expenses on the condensed consolidated balance sheets included the following:

			June 30, 2022						December 31, 2021
			(in thousands)
Accounts payable-trade			$	19,420					$	17,699
Accrued expenses			68,819						62,962
Royalties payable			26,799						24,816
Greenhouse gas liability - current portion			—						7,513
Taxes other than income tax liability			8,469						8,273
Accrued interest			10,682						10,736
Dividends payable			4,726						4,800
Asset retirement obligations - current portion			20,000						20,000
Operating lease liability			1,762						—
Other			6						725
Total accounts payable and accrued expenses			$	160,683					$	157,524

The decrease of $4 million in the long-term portion of the asset retirement obligations from $144 million at December 31, 2021 to $140 million at June 30, 2022 was due to $11 million of liabilities settled during the period, and a $1 million reduction related to property sales. These decreases were offset by $5 million of accretion and $3 million of liabilities incurred.

Other noncurrent liabilities at June 30, 2022 included approximately $26 million of greenhouse gas liability and $6 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 June 30, 2022, other operating expenses were less than $1 million. For the three months ended June 30, 2021, other operating expenses mainly consisted of $2 million of supplemental property tax assessments and royalty audit charges, mostly offset by $2 million of employee retention credits.

For the six months ended June 30, 2022, other operating expenses were $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 six months ended June 30, 2021, other operating expenses were approximately $1 million and mainly consisted of approximately $3 million of supplemental property tax assessments and royalty audit charges and tank rental costs, partially offset by $2 million of employee retention credits.

Supplemental Cash Flow Information

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

			Six Months Ended June 30,
			2022						2021
			(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties			$	1,011					$	1,437
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized			$	14,988					$	14,925
Income taxes payments			$	2,484					$	—

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 June 30, 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 June 30, 2022, 3,419,000 incremental RSU and PSU shares were included in the diluted EPS calculation. For the three months ended June 30, 2021 and the six months ended June 30, 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 June 30,												Six Months Ended June 30,
			2022						2021						2022						2021
			(in thousands except per share amounts)
Basic EPS calculation
Net income (loss)			$	43,354					$	(12,881)					$	(13,456)					$	(34,203)
Weighted-average shares of common stock outstanding			79,596						80,471						79,945						80,294
Basic income (loss) per share			$	0.54					$	(0.16)					$	(0.17)					$	(0.43)
Diluted EPS calculation
Net income (loss)			$	43,354					$	(12,881)					$	(13,456)					$	(34,203)
Weighted-average shares of common stock outstanding			79,596						80,471						79,945						80,294
Dilutive effect of potentially dilutive securities(1)			3,419						—						—						—
Weighted-average common shares outstanding - diluted			83,015						80,471						79,945						80,294
Diluted income (loss) per share			$	0.52					$	(0.16)					$	(0.17)					$	(0.43)

(1)    We excluded 2.9 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for the three months ended June 30, 2021, because their effect was anti-dilutive. We excluded approximately 3.5 million and 2.6 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for the six months ended June 30, 2022 and June 30, 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 and six months ended June 30, 2022 and 2021:

			Three Months Ended June 30,												Six Months Ended June 30,
			2022						2021						2022						2021
			(in thousands)
Oil sales			$	230,617					$	141,309					$	433,341					$	263,668
Natural gas sales			7,349						5,415						13,331						17,492
Natural gas liquids sales			2,105						1,051						3,750						1,880
Service revenue			46,178						—						86,014						—
Electricity sales			7,419						6,888						12,838						16,957
Marketing revenues			—						121						289						2,355
Other revenues			120						118						165						255
Revenues from contracts with customers			293,788						154,902						549,728						302,607
Losses on oil and gas sales derivatives			(40,658)						(55,653)						(202,516)						(109,157)
Total revenues and other			$	253,130					$	99,249					$	347,212					$	193,450

Note 9—Acquisition and Divestiture

Note 10—Segment Information

			Three Months Ended June 30, 2022
			Development & Production						Well Servicing and Abandonment						Corporate/Eliminations						Consolidated Company
			(in thousands)
Revenues - excluding hedges			$	247,610					$	46,178					$	—					$	293,788
Net income (loss)			$	68,885					$	3,307					$	(28,838)					$	43,354
Adjusted EBITDA			$	116,942					$	6,200					$	(13,395)					$	109,747
Capital expenditures			$	32,134					$	1,066					$	886					$	34,086
Total assets			$	1,456,164					$	71,543					$	2,678					$	1,530,385

			Six Months Ended June 30, 2022
			Development & Production						Well Servicing and Abandonment						Corporate/Eliminations						Consolidated Company
			(in thousands)
Revenues - excluding hedges			$	463,714					$	86,014					$	—					$	549,728
Net income (loss)			$	34,594					$	3,023					$	(51,073)					$	(13,456)
Adjusted EBITDA			$	222,591					$	9,500					$	(26,632)					$	205,459
Capital expenditures			$	58,571					$	1,694					$	1,441					$	61,706
Total assets			$	1,456,164					$	71,543					$	2,678					$	1,530,385

Adjusted EBITDA is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources to and assessing performance of each segment. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. Adjusted EBITDA is calculated 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 unusual and infrequent items. While Adjusted EBITDA is a non-GAAP measure, the amounts included in the calculations of Adjusted EBITDA, were computed in accordance with GAAP. This measure is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative to, or more meaningful than, income and liquidity measures calculated in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

			Three Months Ended June 30, 2022
			Development & Production						Well Servicing and Abandonment						Corporate/Eliminations						Consolidated Company
			(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)			$	68,885					$	3,307					$	(28,838)					$	43,354
Add (Subtract):
Interest expense			—						—						7,729						7,729
Income tax expense			—						—						2,145						2,145
Depreciation, depletion, and amortization			33,956						3,017						1,082						38,055
Losses on derivatives			51,319						—						—						51,319
Net cash paid for scheduled derivative settlements			(37,628)						—						—						(37,628)
Other operating expenses (income)			30						(210)						533						353
Stock compensation expense			380						86						3,954						4,420
Adjusted EBITDA			$	116,942					$	6,200					$	(13,395)					$	109,747

			Six Months Ended June 30, 2022
			Development & Production						Well Servicing and Abandonment						Corporate/Eliminations						Consolidated Company
			(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)			$	34,594					$	3,023					$	(51,073)					$	(13,456)
Add (Subtract):
Interest expense			—						—						15,404						15,404
Income tax benefit			—						—						(1,206)						(1,206)
Depreciation, depletion, and amortization			69,430						6,196						2,206						77,832
Losses on derivatives			184,123						—						—						184,123
Net cash paid for scheduled derivative settlements			(69,780)						—						—						(69,780)
Other operating expenses (income)			3,525						(36)						633						4,122
Stock compensation expense			699						119						7,404						8,222
Non-recurring costs			—						198						—						198
Adjusted EBITDA			$	222,591					$	9,500					$	(26,632)					$	205,459

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 June 30, 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 components of lease expense are as follows:

			Three Months Ended June 30, 2022						Six Months Ended June 30, 2022
			(in thousands)
Lease Cost
Operating lease cost			$	503					$	986
Total net lease cost			$	503					$	986

The following table presents supplemental interim consolidated balance sheet information related to leases as of June 30, 2022.

			Six Months Ended June 30, 2022						Balance Sheet Classification
			(in thousands)
Leases
Assets
Operating lease assets			$	7,150					Other noncurrent assets
Total assets			$	7,150
Liabilities
Operating lease liability			$	1,762					Accounts payable and accrued expenses
Operating lease noncurrent liability			6,017						Other noncurrent liabilities
Total liabilities			$	7,779

						Six Months Ended June 30, 2022
Long-Term and Discount Rate
Weighted-average remaining lease term:
Operating Lease						4.7 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 June 30, 2022.

						As of June 30, 2022
						Operating Leases
						(in thousands)
2022						$	1,082
2023						1,963
2024						1,650
2025						1,542
2026						1,549
Thereafter						934
Total lease payments						8,720
Less imputed interest						(941)
Total lease obligations						7,779
Less current obligations						(1,762)
Long-term lease obligations						$	6,017

Supplemental unaudited interim consolidated cash flow information related to leases is as follows:

						Six Months Ended June 30, 2022
						(in thousands)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases						$	1,052
ROU assets obtained in exchange for operating lease liabilities						$	7,956

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 and gas reserves in the San Joaquin basin of California and the Uinta basin of Utah, 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 assets in our D&P business, in the aggregate, are characterized by high oil content (our California assets are 100% oil) and are predominantly located 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 typically 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.

On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which operates as CJWS and now constitutes our well servicing and abandonment segment. 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 (IPO) in July 2018, we have demonstrated our commitment to returning a substantial amount of capital to shareholders and in 2022, we reinforced this commitment by initiating a shareholder return model designed to significantly increase cash returns to our shareholders from our Discretionary Free Cash Flow (as defined and discussed below). In accordance with the shareholder return model, in May 2022, we declared our first variable dividend payment of $0.13 per share based on Discretionary Free Cash Flow generated in the first

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 a 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 shareholder return 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 Discretionary Free Cash Flow to fund our operations and optimize capital efficiency, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles. “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 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) Adjusted EBITDA; (b) Discretionary Free Cash Flow for shareholder returns; (c) operating expenses; (d) environmental, health & safety (“EH&S”) results; (e) general and administrative expenses; (f) production from our D&P business; and (g) the performance of our well servicing and abandonment operations based on activity levels, pricing and relative performance for each service provided.

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. We also use Adjusted EBITDA in planning our capital allocation to sustain production levels and determining our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility (defined below in Liquidity and Capital Resources). 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. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliation of Adjusted EBITDA to net (loss) income, our most directly comparable financial measure calculated and presented in accordance with GAAP.

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, as well as contracts for the transportation of fuel gas from the Rockies which has 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.

Well Servicing and Abandonment Operations Performance

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 geopolitical and global economic conditions and third-party transportation and market takeaway infrastructure capacity. While oil prices have significantly improved in 2022 relative to the lows experienced in 2020 and recoveries through 2021, they are still subject to volatility. We utilize derivatives 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; our 2021 RBL Facility (defined below in Liquidity and Capital Resources) also has hedging requirements.

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.

The COVID-19 pandemic resulted in a severe decrease in demand for oil, which created significant volatility and uncertainty in the oil and gas industry during 2020 and 2021. When combined with an excess supply of oil and related products, oil prices declined significantly in the first half of 2020. Although there has been some increasing volatility, overall oil prices have steadily improved since the lows experienced in 2020, in line with increasing demand despite the ongoing pandemic and uncertainties surrounding the COVID-19 variants. Oil and natural gas prices increased significantly during 2022, reaching a high of $123 during the second quarter, primarily due to global supply and demand imbalances. Brent prices were 14% and 62% higher for the three months ended June 30, 2022 as compared to the three months ended March 31, 2022 and June 30, 2021, respectively. Currently, global oil inventories are low relative to historical levels and supply increases from OPEC+ and other oil producing nations are not expected to be sufficient to meet forecasted oil demand growth for the next few years. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental oil supplies over the past few years. Furthermore, sanctions and import bans on Russian oil have been implemented by various countries in response to the war in Ukraine, further impacting global oil supply. Still, oil and natural gas prices have recently declined from the highs experienced in second quarter of 2022 and could decline further with any decrease in demand due to, among other things, uncertainty and volatility from global supply chain disruptions attributable to the pandemic, the ongoing conflict in Ukraine, international sanctions, speculation as to future actions by OPEC+, developing COVID-19 variants and the potential for a widespread COVID-19 outbreak, higher gas prices, increasing inflation and government efforts to reduce inflation, and possible changes in the overall health of the global economy, including a prolonged recession. Further, the volatility in oil and natural gas prices could accelerate a transition away from fossil fuels, resulting in reduced demand over the longer term. To what extent these and other external factors (such as government action with respect to climate change regulation) ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors, including future developments, that are not within our control and cannot be accurately predicted.

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. We utilize derivatives 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.

Average oil prices, as noted below, were higher for the three months ended June 30, 2022 compared to the three months ended March 31, 2022 and June 30, 2021. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics, including third-party transportation and market takeaway infrastructure capacity.

In California, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, which was as high as $9.69 per mmbtu and as low as $5.15 per mmbtu during the second quarter of 2022, while we paid an average of $7.30 per mmbtu in this period.

The following table presents the average Brent, WTI, Kern, Delivered, and Henry Hub prices for the three months ended June 30, 2022, March 31, 2022 and June 30, 2021 and for the six months ended June 30, 2022 and June 30, 2021:

			Three Months Ended																		Six Months Ended
			June 30, 2022						March 31, 2022						June 30, 2021						June 30, 2022						June 30, 2021
Oil (bbl) – Brent			$	111.98					$	97.90					$	69.08					$	104.94					$	65.23
Oil (bbl) – WTI			$	108.71					$	94.54					$	66.03					$	101.67					$	61.95
Natural gas (mmbtu) – Kern, Delivered			$	7.36					$	4.83					$	3.23					$	6.10					$	5.60
Natural gas (mmbtu) – Henry Hub			$	7.50					$	4.67					$	2.95					$	6.08					$	3.22

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 their differentials are strongly affected by local market fundamentals, availability of third-party transportation and market takeway infrastructure 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 contracts with terms ending in December 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.

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 compliance with CEQA to CalGEM. Demonstrating CEQA compliance without being able to reference the Kern County EIR or another CEQA-compliant EIR is a more technical, time and cost intensive process and may, among other things, require that we conduct an extensive 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 for new wells. We have not experienced delays in the issuance of permits for the workover of existing wells or other activities re-using existing well bores, for which the environmental review is expedited because the well already exists.

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 have been and in the future may be impacted by ice and snow in the winter, especially in Utah, by electrical storms and high temperatures in the spring and summer, and 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 and second quarters 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 and six months ended June 30, 2022, our consolidated capital expenditures were approximately $34 million and $62 million, respectively, on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement spending. Approximately 54% and 35% of capital expenditures for the six months ended June 30, 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, the planned use of which is expected to keep our annual production relatively flat to 2021 after taking into account the impact of acquisitions and divestitures completed earlier this year. We currently anticipate our capital expenditures will be at the lower end of the guidance range because the execution of our 2022 capital development program now reflects an increase in workover and other activities re-using existing well bores and drilling fewer new wells due to delays in permit issuance by CalGEM. We expect 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 program with cash flow from operations.

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 permit inventory to support planned activities, commodity prices, storage and third-party transportation 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 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 $6 million and $11 million for plugging and abandonment activities in the three months and six months ended June 30, 2022, respectively. Our well servicing and abandonment segment expects to plug and abandon approximately 2,500 to 3,000 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
			June 30, 2022						March 31, 2022						June 30, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales			$	204,706					$	186,252					$	129,128
Operating income(1)			$	63,608					$	60,162					$	11,413
Depreciation, depletion, and amortization (DD&A)			$	34,074					$	35,786					$	35,174
Average daily production (mboe/d)			21.0						22.2						21.7
Production (oil % of total)			100		%				100		%				100		%
Realized sales prices:
Oil (per bbl)			$	107.31					$	93.16					$	65.37
NGLs (per bbl)			$	—					$	—					$	—
Gas (per mcf)			$	—					$	—					$	—
Capital expenditures(2)			$	18,672					$	14,622					$	31,303