Item 2. Management’s Discussion and Analysis
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an independent energy and carbon management company committed to energy transition. We produce some of the lowest carbon intensity oil in the United States according to a joint report by Ceres and the Clean Air Task Force and we are focused on maximizing the value of our land, minerals and technical resources for decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects and other emissions reducing projects in California. We intend to pursue some or all of these projects through our Carbon TerraVault JV that we formed with BGTF Sierra Aggregator LLC (Brookfield) . While all of these projects are in early stages, we expect that the size and scope of our projects providing these and similar services and capital spent on such projects will continue to grow given our strategy of expansion into carbon management. For more information about the risks involved in our carbon capture projects, see Part I, Item 1A – Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2022 (2022 Annual Report) and for more information on the Carbon TerraVault JV, see Part I, Item 1 – Financial Statements, Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions.
Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated subsidiaries.
Business Environment and Industry Outlook
Commodity Prices
Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term.
Global oil prices declined slightly in the three months ended June 30, 2023 compared to the three months ended March 31, 2023 as global demand for oil remained generally flat. The decrease in natural gas index prices during the three months ended June 30, 2023 compared to the three months ended March 31, 2023 occurred as North American natural gas production and storage inventories remained relatively high in the second quarter. Refer to Prices and Realizations below for additional information our realized prices.
The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:
Three months ended Six months ended
June 30, 2023 March 31, 2023 June 30, 2023 June 30, 2022
Brent oil ($/Bbl) $ 78.01 $ 82.22 $ 80.12 $ 104.59
WTI oil ($/Bbl) $ 73.78 $ 76.13 $ 74.95 $ 101.35
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price $ 2.10 $ 3.42 $ 2.76 $ 6.06
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Regulatory Updates
CalGEM is California's primary regulator of the oil and natural gas production industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. From time to time we have experienced significant delays with respect to obtaining drilling permits from CalGEM for our operations. A variety of factors outside of our control can lead to such delays. Since December 2022, CalGEM has issued a limited number of permits for new production wells in California, and those permits were issued to other operators. We continue to receive permits from CalGEM for workovers, deepenings, sidetracks and plugging and abandonment operations. For more information, see Part I, Item 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate in our 2022 Annual Report.
Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by the City of Long Beach and CalGEM. We are currently in discussions with the City of Long Beach and CalGEM with respect to what injection well pressure gradient complies with CalGEM’s regulatory requirements for the protection of underground sources of drinking water, while at the same time mitigating subsidence risks. CalGEM's local office has preliminarily indicated that the injection well pressure gradient should be reduced from the gradient that has been used for several decades. As part of our ongoing discussions, we and the City of Long Beach have provided CalGEM with technical information regarding how the historical injection well pressure gradient complies with CalGEM's requirements, as well as the Clean Water Act, and to inform them of the absence of risk of leakage from the injection zone. CalGEM has proposed a meeting for CRC and the City of Long Beach to present their technical findings in more detail, to occur in or around August 2023. As part of that meeting, and subject to its outcome, CalGEM has also proposed that CRC and the City of Long Beach present a work plan for the reduction of injection pressures over a six-month period to levels acceptable to CalGEM. We are in the process of preparing a response and continue to believe that existing injection pressures address subsidence risks and are protective of underground sources of drinking water. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient, and we were unable to reverse that decision on appeal or other legal challenge, we expect any material reduction in injection well pressure gradient for our operations in the Wilmington Oil Field would result in a decrease in production and reserves from the field. For additional information, see Part I, Item 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities and the Risk factor entitled " Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans " in our 2022 Annual Report.
Supply Chain Constraints and Inflation
In 2023, we have experienced relatively flat pricing compared to 2022. Labor costs and national electricity prices have risen which has partially negated the benefits of supply chains opening up in 2023. Further, we have been unable to obtain price reductions from our vendors for certain purchased goods, including OCTG, wellbore tubulars and chemicals. These categories have raw material inputs such as steel and diesel fuel which have experienced intermediate price spikes throughout the first half of 2023 preventing our vendors from offering price reductions for these items.
We have taken measures to limit the effects of inflation by entering into contracts for materials and services with terms of one to three years. For contracts that we anticipate renegotiating in the second half of 2023, we expect moderate price increases for certain purchased goods and services. We also continue to look at ways to improve productivity and performance from our workforce and our vendors.
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Production
The following table sets forth our average net production of oil, NGLs and natural gas per day in each of the California oil and natural gas basins in which we operated for the periods presented.
Three months ended Six months ended
June 30, 2023 March 31, 2023 June 30, 2023 June 30, 2022
Oil (MBbl/d)
San Joaquin Basin 34 35 35 38
Los Angeles Basin 19 20 19 17
Total 53 55 54 55
NGLs (MBbl/d)
San Joaquin Basin 11 11 11 11
Total 11 11 11 11
Natural gas (MMcf/d)
San Joaquin Basin 119 119 119 127
Los Angeles Basin 1 1 1 1
Sacramento Basin 15 16 16 18
Total 135 136 136 146
Total Net Production (MBoe/d) 86 89 88 90
Total daily net production for the three months ended June 30, 2023, compared to the three months ended March 31, 2023 decreased by 3 MBoe/d largely due to natural decline and changes in NGL storage volumes. This decrease was partially offset by increased production from drilling and workover activity. Our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the three months ended June 30, 2023 compared to the three months ended March 31, 2023.
Total daily net production for the six months ended June 30, 2023, compared to the same prior year period decreased by 2 MBoe/d largely due to natural decline partially offset by increased production from drilling and workover activity. Our PSCs positively impacted our production by 2 MBoe/d in the six months ended June 30, 2023 compared to the same prior year period.
The following table reconciles our average net production to our average gross production (which includes production from the fields we operate and our share of production from fields operated by others) for the periods presented:
Three months ended Six months ended
June 30, 2023 March 31, 2023 June 30, 2023 June 30, 2022
(MBoe/d)
Total Net Production 86 89 88 90
Partners' share under PSC-type contracts 7 6 6 7
Working interest and royalty holders' share 8 7 8 8
Changes in NGL inventory and other 2 1 1 1
Total Gross Production 103 103 103 106
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Production-Sharing Contracts (PSCs)
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure which adjusts for excess costs attributable to PSC-type contracts for the periods presented in the tables below:
Three months ended
June 30, 2023 March 31, 2023
(in millions) ($ per Boe) (in millions) ($ per Boe)
Operating costs $ 186 $ 23.71 $ 254 $ 31.61
Excess costs attributable to PSC-type contracts (17) $ (2.15) (18) $ (2.23)
Operating costs, excluding effects of PSC-type contracts $ 169 $ 21.56 $ 236 $ 29.38
Six months ended
June 30, 2023 June 30, 2022
(in millions) ($ per Boe) (in millions) ($ per Boe)
Operating costs $ 440 $ 27.71 $ 372 $ 22.90
Excess costs attributable to PSC-type contracts (35) $ (2.19) (40) $ (2.45)
Operating costs, excluding effects of PSC-type contracts $ 405 $ 25.52 $ 332 $ 20.45
For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2022 Annual Report.
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Prices and Realizations
The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX indexes for our products for the periods presented:
Three months ended
June 30, 2023 March 31, 2023
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 78.01 $ 82.22
Realized price without derivative settlements $ 75.77 97% $ 78.68 96%
Derivative settlements (12.11) (15.64)
Realized price with derivative settlements $ 63.66 82% $ 63.04 77%
WTI $ 73.78 $ 76.13
Realized price without derivative settlements $ 75.77 103% $ 78.68 103%
Realized price with derivative settlements $ 63.66 86% $ 63.04 83%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 42.48 54% $ 58.88 72%
Realized price (% of WTI) $ 42.48 58% $ 58.88 77%
Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.10 $ 3.42
Realized price without derivative settlements ($/Mcf) $ 3.46 165% $ 21.56 630%
Derivative settlements — —
Realized price with derivative settlements ($/Mcf) $ 3.46 165% $ 21.56 630%
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Six months ended
June 30, 2023 June 30, 2022
Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 80.12 $ 104.59
Realized price without derivative settlements $ 77.25 96% $ 104.07 100%
Derivative settlements (13.90) (42.36)
Realized price with derivative settlements $ 63.35 79% $ 61.71 59%
WTI $ 74.95 $ 101.35
Realized price without derivative settlements $ 77.25 103% $ 104.07 103%
Realized price with derivative settlements $ 63.35 85% $ 61.71 61%
NGLs ($ per Bbl)
Realized price (% of Brent) $ 50.88 64% $ 72.57 69%
Realized price (% of WTI) $ 50.88 68% $ 72.57 72%
Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.76 $ 6.06
Realized price without derivative settlements ($/Mcf) $ 12.44 451% $ 6.58 109%
Derivative settlements — (0.07)
Realized price with derivative settlements ($/Mcf) $ 12.44 451% $ 6.51 107%
Oil — Brent prices decreased slightly for the three months ended June 30, 2023 compared to the three months ended March 31, 2023 as global demand for crude remained generally flat. Oil prices in the six months ended June 30, 2023 were lower than the same prior year period in 2022 as global energy inventories (including crude, refined products and natural gas) stabilized and as Russian crude and refined products continue to reach markets.
NGLs — NGL prices for the three months ended June 30, 2023 decreased compared to the three months ended March 31, 2023 reflecting traditional seasonality in NGL pricing, as well as higher than normal levels of inventory for this time of year. NGL prices for the six months ended June 30, 2023 decreased compared to the same prior year period as prices for competing and complementary products (natural gas, crude oil) have declined. For both periods, California remained a premium market compared to other North American locations.
Natural Gas — Our realized price for natural gas decreased for the three months ended June 30, 2023 compared to the three months ended March 31, 2023 as weather across the West Coast of the United States during the quarter remained moderate and as California storage inventories rebounded from historically low levels. Natural gas prices in the six months ended June 30, 2023 were higher than the same period in 2022 reflecting the unprecedented pricing experienced in California natural gas markets during the first quarter of 2023.
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Statements of Operations Analysis
Results of Oil and Gas Operations
The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended June 30, 2023 and March 31, 2023 and the six months ended June 30, 2023 and 2022. Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Purchased natural gas used to generate steam in our steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation.
Three months ended Six months ended
June 30, 2023 March 31, 2023 June 30, 2023 June 30, 2022
($ per Boe)
Energy operating costs $ 7.39 $ 15.56 $ 11.52 $ 9.24
Gas processing costs $ 0.64 $ 0.62 $ 0.63 $ 0.55
Non-energy operating costs $ 15.68 $ 15.43 $ 15.56 $ 13.11
Operating costs $ 23.71 $ 31.61 $ 27.71 $ 22.90
Field general and administrative expenses (a)
$ 1.40 $ 1.49 $ 1.45 $ 0.92
Field depreciation, depletion and amortization (b)
$ 6.50 $ 6.72 $ 6.61 $ 5.29
Field taxes other than on income $ 3.70 $ 3.73 $ 3.72 $ 3.20
a. Excludes unallocated general and administrative expenses.
b. Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.
Operating costs decreased during the three months ended June 30, 2023 compared to the three months ended March 31, 2023 primarily due to lower energy operating costs as natural gas prices in California markets declined between quarters. Operating costs were higher in the six months ended June 30, 2023 compared to the same prior year period primarily due to increased energy operating costs as natural gas prices in California experienced unprecedented highs during the first quarter of 2023. Lower production volumes also contributed to the increase on a per Boe basis.
Field depreciation, depletion and amortization decreased slightly during the three months ended June 30, 2023 compared to the three months ended March 31, 2023 due to lower production volumes. Field depreciation, depletion and amortization increased during the six months ended June 30, 2023 compared to the same prior year period primarily due to a change in our depreciation, depletion and amortization rates which are periodically adjusted to reflect current reserve estimates. This increase was partially offset by lower production volumes in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. Lower production volumes also contributed to the increase on a per Boe basis.
Consolidated Results of Operations
For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 12 Condensed Consolidated Financial Information.
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Three months ended June 30, 2023 compared to March 31, 2023
The following table presents our operating revenues for the three months ended June 30, 2023 and March 31, 2023:
Three months ended
June 30, 2023 March 31, 2023
(in millions)
Oil, natural gas and NGL sales $ 447 $ 715
Net gain from commodity derivatives 31 42
Sales of purchased natural gas 72 184
Electricity sales 34 68
Other revenue 7 15
Total operating revenues $ 591 $ 1,024
Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $447 million for the three months ended June 30, 2023, which is a decrease of $268 million compared to $715 million for the three months ended March 31, 2023. This decrease was primarily due to lower realized prices for the second quarter of 2023 as shown in the table below.
Oil NGLs Natural Gas Total
(in millions)
Three months ended March 31, 2023 $ 390 $ 62 $ 263 $ 715
Changes in realized prices (15) (18) (221) (254)
Changes in production (13) (2) 1 (14)
Three months ended June 30, 2023 $ 362 $ 42 $ 43 $ 447
Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
The effect of cash settlements on our commodity derivative contracts is not included in the table above. Payments on commodity derivatives were $63 million for the three months ended June 30, 2023 compared to $65 million for the three months ended March 31, 2023. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales decreased by $266 million compared to the three months ended March 31, 2023.
Net gain from commodity derivatives — Net gain from commodity derivatives was $31 million for the three months ended June 30, 2023 compared to $42 million for the three months ended March 31, 2023. The change primarily resulted from non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward curves:
Three months ended
June 30, 2023 March 31, 2023
(in millions)
Non-cash commodity derivative gain $ 94 $ 107
Net cash payments on settled commodity derivatives (63) (65)
Net gain from commodity derivatives $ 31 $ 42
Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were $72 million for the three months ended June 30, 2023, a decrease of $112 million from $184 million during the three months ended March 31, 2023. The decrease was primarily the result of lower market prices for natural gas. Our natural gas sales net of related purchased natural gas expense were $45 million for the three months ended June 30, 2023 compared to $60 million for the three months ended March 31, 2023.
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Electricity sales — Electricity sales decreased by $34 million to $34 million for the three months ended June 30, 2023 compared to $68 million for the three months ended March 31, 2023 predominately due to higher power prices during the first quarter of 2023.
The following table presents our operating and non-operating expenses and income for the three months ended June 30, 2023 and March 31, 2023:
Three months ended
June 30, 2023 March 31, 2023
(in millions)
Operating expenses
Energy operating costs $ 58 $ 125
Gas processing costs 5 5
Non-energy operating costs 123 124
General and administrative expenses 71 65
Depreciation, depletion and amortization 56 58
Asset impairment — 3
Taxes other than on income 42 42
Exploration expense 1 1
Purchased natural gas expense 27 124
Electricity generation expenses 13 49
Transportation costs 16 17
Accretion expense 11 12
Other operating expenses, net 21 13
Total operating expenses 444 638
Gain on asset divestitures — 7
Operating income 147 393
Non-operating (expenses) income
Interest and debt expense (14) (14)
Loss from investment in unconsolidated subsidiary (1) (2)
Other non-operating (expense) income 3 (1)
Income before income taxes 135 376
Income tax provision (38) (75)
Net income $ 97 $ 301
Energy operating costs — Energy operating costs for the three months ended June 30, 2023 were $58 million, which was a decrease of $67 million from $125 million for the three months ended March 31, 2023. This decrease was a result of lower natural gas prices in the second quarter of 2023. For more information on our natural gas market prices, see Prices and Realizations above.
Non-energy operating costs — Non-energy operating costs includes $3 million and $1 million of stock-based compensation expense related to our cash-settled awards for the three months ended June 30, 2023 and March 31, 2023, respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.
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General and administrative expenses — General and administrative (G&A) expenses were $71 million for the three months ended June 30, 2023, which was an increase of $6 million from $65 million for the three months ended March 31, 2023. The increase in G&A expenses was primarily attributable to compensation-related expenses including accelerated vesting for certain departing employees and new stock-based compensation awards granted. Stock-based compensation awards are discussed further below.
The table below shows G&A expenses for our exploration and production business (including unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business do not include expenses borne by the Carbon TerraVault JV.
Three months ended
June 30, 2023 March 31, 2023
(in millions)
Exploration and production, corporate and other
$ 68 $ 62
Carbon management business
3 3
Total general and administrative expenses $ 71 $ 65
Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.
Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.
Stock-based compensation included in G&A expense is shown in the table below:
Three months ended
June 30, 2023 March 31, 2023
(in millions)
Cash-settled awards
$ 5 $ 3
Stock-settled awards
8 6
Total included in general and administrative expenses $ 13 $ 9
Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $27 million of natural gas for marketing activities during the three months ended June 30, 2023, which was a decrease of $97 million from $124 million for the three months ended March 31, 2023. The decrease was predominantly the result of a decline in marketing activity and lower market prices in the three months ended June 30, 2023 compared to the three months ended March 31, 2023. For more information on our natural gas market prices, see Prices and Realizations above.
Electricity generation expenses — Electricity generation expenses for the three months ended June 30, 2023 were $13 million, which was a decrease of $36 million from $49 million for the three months ended March 31, 2023. This decrease was primarily due to lower prices for natural gas.
Income taxes – The income tax provision for the three months ended June 30, 2023 was $38 million (effective tax rate of 28%), compared to $75 million (effective tax rate of 20%) for the three months ended March 31, 2023. Excluding the effect of the change in valuation allowance, our effective tax rate would have been 28% in the three months ended March 31, 2023. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on a valuation allowance related to our Lost Hills divestiture.
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Six months ended June 30, 2023 compared to June 30, 2022
The following table presents our operating revenues for the six months ended June 30, 2023 and 2022:
Six months ended
June 30, 2023 June 30, 2022
(in millions)
Oil, natural gas and NGL sales $ 1,162 $ 1,346
Net gain (loss) from commodity derivatives 73 (662)
Sales of purchased natural gas 256 107
Electricity sales 102 83
Other revenue 22 26
Total operating revenues $ 1,615 $ 900
Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,162 million for the six months ended June 30, 2023, which is a decrease of $184 million compared to $1,346 million for the six months ended June 30, 2022. This decrease was primarily due to changes in realized prices as shown in the table below, including lower realized prices for oil and NGLs partially offset by higher realized prices for natural gas.
Oil NGLs Natural Gas Total
(in millions)
Six months ended June 30, 2022 $ 1,033 $ 139 $ 174 $ 1,346
Changes in realized prices (266) (42) 155 (153)
Changes in production (15) 7 (23) (31)
Six months ended June 30, 2023 $ 752 $ 104 $ 306 $ 1,162
Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
The effect of cash settlements on our commodity derivative contracts is not included in the table above. Payments on commodity derivatives were $128 million for the six months ended June 30, 2023 compared to payments of $422 million for the six months ended June 30, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $110 million compared to the six months ended June 30, 2022.
Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $73 million for the six months ended June 30, 2023 compared to a net loss of $662 million for the six months ended June 30, 2022. The change primarily resulted from non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward curves:
Six months ended
June 30, 2023 June 30, 2022
(in millions)
Non-cash commodity derivative gain (loss) $ 201 $ (240)
Net cash payments on settled commodity derivatives (128) (422)
Net gain (loss) from commodity derivatives $ 73 $ (662)
Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were $256 million for the six months ended June 30, 2023, an increase of $149 million from $107 million during the six months ended June 30, 2022. The increase was primarily the result of higher marketing activity and higher market prices in 2023. Our natural gas sales net of related purchased natural gas expense were $105 million for the six months ended June 30, 2023 compared to $19 million for the six months ended June 30, 2022.
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Electricity sales — Electricity sales increased by $19 million to $102 million for the six months ended June 30, 2023 compared to $83 million for the six months ended June 30, 2022. The increase was predominately a result of higher power prices in the first quarter of 2023 compared to the prior year. Our electricity sales net of electricity generation expenses were $40 million for the six months ended June 30, 2023 compared to $26 million for the six months ended June 30, 2022.
The following table presents our operating and non-operating expenses and income for the six months ended June 30, 2023 and 2022:
Six months ended
June 30, 2023 June 30, 2022
(in millions)
Operating expenses
Energy operating costs $ 183 $ 150
Gas processing costs 10 9
Non-energy operating costs 247 213
General and administrative expenses 136 104
Depreciation, depletion and amortization 114 99
Asset impairment 3 2
Taxes other than on income 84 76
Exploration expense 2 2
Purchased natural gas expense 151 88
Electricity generation expenses 62 57
Transportation costs 33 24
Accretion expense 23 22
Other operating expenses, net 34 23
Total operating expenses 1,082 869
Gain (loss) on asset divestitures 7 58
Operating income 540 89
Non-operating (expenses) income
Interest and debt expense (28) (26)
Loss from investment in unconsolidated subsidiary (3) —
Other non-operating (expense) income 2 2
Income before income taxes 511 65
Income tax provision (113) (50)
Net income $ 398 $ 15
Energy operating costs — Energy operating costs for the six months ended June 30, 2023 were $183 million, which was an increase of $33 million from $150 million for the six months ended June 30, 2022. This increase was a result of higher prices in the first six months of 2023 compared to the same prior year period. For more information on our natural gas market prices, see Prices and Realizations above.
Non-energy operating costs — Non-energy operating costs were $247 million for the six months ended June 30, 2023, which was an increase of $34 million from $213 million for the six months ended June 30, 2022. The increase was predominately a result of higher downhole maintenance activity. Non-energy operating costs also includes $4 million and $2 million of stock-based compensation expense related to our cash-settled awards for the six months ended June 30, 2023 and 2022, respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.
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General and administrative expenses — General and administrative (G&A) expenses were $136 million for the six months ended June 30, 2023, which was an increase of $32 million from $104 million for the six months ended June 30, 2022. The increase in G&A expenses was primarily attributable to compensation-related expenses, including stock-based compensation awards granted in 2023, and higher spending on information technology infrastructure. Stock-based compensation awards are discussed further below.
The table below shows G&A expenses for our exploration and production business (in addition to unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business do not include expenses borne by the Carbon TerraVault JV.
Six months ended
June 30, 2023 June 30, 2022
(in millions)
Exploration and production, corporate and other
$ 130 $ 99
Carbon management business
6 5
Total general and administrative expenses $ 136 $ 104
Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.
Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.
Stock-based compensation included in G&A expense is shown in the table below:
Six months ended
June 30, 2023 June 30, 2022
(in millions)
Cash-settled awards
$ 8 $ 4
Stock-settled awards
14 8
Total included in general and administrative expenses $ 22 $ 12
Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) increased $15 million to $114 million for the six months ended June 30, 2023 from $99 million for the six months ended June 30, 2022. The increase was primarily due to a change in our DD&A rates which are periodically adjusted to reflect current reserve estimates.
Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $151 million of natural gas for marketing activities during the six months ended June 30, 2023, which was an increase of $63 million from $88 million for the six months ended June 30, 2022. The increase was predominantly the result of higher marketing activity levels and higher market prices in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. For more information on our natural gas market prices, see Prices and Realizations above.
Income taxes – The income tax provision for the six months ended June 30, 2023 was $113 million (effective tax rate of 22%), compared to $50 million (effective tax rate of 77%) for the six months ended June 30, 2022. The income tax provision for the six months ended June 30, 2022 included a valuation allowance related to our Lost Hills divestiture that was released in the six months ended June 30, 2023. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on a valuation allowance related to our Lost Hills divestiture.
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Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity and capital resources are cash flows from operations, cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the six months ended June 30, 2023 were for capital investments, repurchases of our common stock and dividends.
The following table summarizes our liquidity:
June 30, 2023
(in millions)
Cash and cash equivalents $ 448
Revolving Credit Facility:
Borrowing capacity 627
Outstanding letters of credit (148)
Availability $ 479
Liquidity $ 927
In April 2023 we amended our Revolving Credit Facility and our borrowing base was reaffirmed at $1.2 billion. See Part I, Item 1 – Financial Statements, Note 3 Debt for more information on the amendment to our Revolving Credit Facility.
At current commodity prices and based upon our planned 2023 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, (iii) repurchase outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Cash Flow Analysis
Cash flows from operating activities — For the six months ended June 30, 2023, our operating cash flow increased $77 million, to $418 million from $341 million in the same period in 2022. The increases in operating cash flow for the six months ended June 30, 2023 primarily relates to higher average realized natural gas prices (increasing sales revenue from the natural gas we produce and margins on our marketing and trading activities) in 2023 compared to the same prior-year period. This increase was partially offset by lower production volumes in 2023 as compared to the same period in 2022. The increase in our revenue was partially offset by an increase in operating costs primarily related to higher prices for purchased natural gas and electricity used in our operations.
Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities:
Six months ended
June 30,
2023 2022
(in millions)
Capital investments $ (86) $ (197)
Changes in accrued capital investments (15) 9
Proceeds from divestitures, net — 76
Acquisitions (1) (17)
Other, net (3) —
Net cash used in investing activities $ (105) $ (129)
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Cash flows used in financing activities — The following table provides a comparative summary of net cash used in financing activities:
Six months ended
June 30,
2023 2022
(in millions)
Repurchases of common stock $ (123) $ (167)
Common stock dividends (40) (26)
Issuance of common stock 1 $ —
Debt amendment costs (8) $ —
Shares cancelled for taxes (2) $ —
Net cash used in financing activities $ (172) $ (193)
2023 Capital Program
Our capital program is dynamic in response to commodity price volatility while focusing on oil production and maximizing our free cash flow. We expect our 2023 capital program to range between $200 and $245 million under current conditions with heavier weighting in the second half of the year due to timing of projects and higher expected workover activity and facilities projects. We expect our capital program related to oil and natural gas development to continue to be focused primarily on executing projects using existing permits outside of Kern County.
The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals:
2023 Full Year Estimate Six months ended June 30, 2023
(in millions)
Oil and natural gas operations $165 - $195 $ 75
Carbon management business 5 - 15 1
Corporate and other 30 - 35 10
Total Capital $200 - $245 $ 86
We recently amended and extended our Revolving Credit Facility as described in Part I, Item 1 – Financial Statements, Note 3 Debt , and continue to evaluate refinancing options for our Senior Notes. We also intend to pursue financing options for our carbon management business that are separate from the rest of our business.
Derivatives
Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.
Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended June 30, 2023. See Part I, Item 1 – Financial Statements, Note 5 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2023 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2022 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
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Dividends
On April 28, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend was payable to shareholders of record at the close of business on June 1, 2023 and was paid on June 16, 2023.
On July 28, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record at the close of business on September 1, 2023 and is expected to be paid on September 15, 2023.
The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above.
Share Repurchase Program
Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.1 billion of our common stock through June 30, 2024. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. The total value of shares that may yet be purchased under the Share Repurchase Program totaled $517
million, excluding commissions and excise taxes on repurchases, as of June 30, 2023. The following is a summary of our share repurchases, held as treasury stock for the periods presented:
Total Number of Shares Purchased Total Value of Shares Purchased Average Price Paid per Share
(number of shares) (in millions) ($ per share)
Three months ended June 30, 2022 2,255,445 $ 96 $ 42.57
Three months ended June 30, 2023 1,618,746 $ 64 $ 39.12
Six months ended June 30, 2022 3,923,901 $ 167 $ 42.55
Six months ended June 30, 2023 3,042,510 $ 123 $ 40.12
Inception of Program (May 2021) through June 30, 2023 14,498,770 $ 584 $ 40.18
Note: The total value of shares purchased includes approximately $1 million in the six months ended June 30, 2023 related to excise taxes on share repurchases, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.
Divestitures and Acquisitions
See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for information on our transactions during the three and six months ended June 30, 2023 and 2022.
Lawsuits, Claims, Commitments and Contingencies
We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at June 30, 2023 and December 31, 2022 were not material to our condensed consolidated balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.
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See Part I, Item 1 – Financial Statements, Note 4 Lawsuits, Claims, Commitments and Contingencies for further information.
Critical Accounting Estimates and Significant Accounting and Disclosure Changes
There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our 2022 Annual Report.
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Forward-Looking Statements
This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
• fluctuations in commodity prices, including supply and demand considerations for our products and services;
• decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;
• government policy, war and political conditions and events, including the war in Ukraine and oil sanctions on Russia, Iran and others;
• regulatory actions and changes that affect the oil and gas industry generally and us in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or our carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products;
• the impact of inflation on future expenses and changes generally in the prices of goods and services;
• changes in business strategy and our capital plan;
• lower-than-expected production or higher-than-expected production decline rates;
• changes to our estimates of reserves and related future cash flows, including changes arising from our inability to develop such reserves in a timely manner, and any inability to replace such reserves;
• the recoverability of resources and unexpected geologic conditions;
• general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;
• production-sharing contracts' effects on production and operating costs;
• the lack of available equipment, service or labor price inflation;
• limitations on transportation or storage capacity and the need to shut-in wells;
• any failure of risk management;
• results from operations and competition in the industries in which we operate;
• our ability to realize the anticipated benefits from prior or future efforts to reduce costs;
• environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);
• the creditworthiness and performance of our counterparties, including financial institutions, operating partners, CCS project participants and other parties;
• reorganization or restructuring of our operations;
• our ability to claim and utilize tax credits or other incentives in connection with our CCS projects;
• our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;
• our ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;
• our ability to maximize the value of our carbon management business and operate it on a stand alone basis;
• our ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;
• uncertainty around the accounting of emissions and our ability to successfully
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gather and verify emissions data and other environmental impacts;
• changes to our dividend policy and share repurchase program, and our ability to declare future dividends or repurchase shares under our debt agreements;
• limitations on our financial flexibility due to existing and future debt;
• insufficient cash flow to fund our capital plan and other planned investments and return capital to shareholders;
• changes in interest rates;
• our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or obtain separate financing for our carbon management business;
• changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations;
• effects of hedging transactions;
• the effect of our stock price on costs associated with incentive compensation;
• inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and our ability to achieve any expected synergies;
• disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;
• pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic; and
• other factors discussed in Part I, Item 1A – Risk Factors in our 2022 Annual Report .
We caution you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and we undertake no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.