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 endedDecember 31, 2021 (the "Annual Report") filed with theSecurities 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 toOctober 1, 2021 ,Berry Corporation (bry) , aDelaware corporation (formerly known asBerry Petroleum Corporation ,"Berry Corp. "), together with its subsidiaryBerry Petroleum, LLC , aDelaware limited liability company ("Berry LLC "); and (ii) for periods on or afterOctober 1, 2021 ,Berry Corp. together with its subsidiaries,Berry LLC ,CJ Berry Well Services Management, LLC , aDelaware limited liability company ("C&J Management"), andC&J Well Services, LLC , aDelaware limited liability company ("C&J"). Our Company We are a westernUnited States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional oil and gas reserves in theSan Joaquin basin ofCalifornia and the Uinta basin ofUtah , with well servicing and abandonment capabilities inCalifornia . SinceOctober 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 (ourCalifornia assets are 100% oil) and are predominantly located in rural areas with low population. InCalifornia , we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. TheCalifornia oil market has primarily Brent-influenced pricing which has typically realized premium pricing to WTI. All of ourCalifornia assets are located in the oil-rich reservoirs in theSan 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 ofUtah . InJanuary 2022 , we divested our natural gas properties in the Piceance basin ofColorado . OnOctober 1, 2021 , we completed the acquisition of one of the largest upstream well servicing and abandonment businesses inCalifornia , which operates as CJWS and now constitutes our well servicing and abandonment business segment. CJWS provides wellsite services inCalifornia 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 theState of California to reduce fugitive emissions - including methane and carbon dioxide - from idle wells. There are approximately 35,000 idle wells estimated to be inCalifornia according to third-party sources. We believe that CJWS is uniquely positioned to capture both state and federal funds to help remediate orphaned idle wells that are a burden of the State, in addition to helping third-party customers safely plug and abandon their idle wells. Since our Initial Public Offering (IPO) inJuly 2018 , we have demonstrated our commitment to maximizing shareholder value and returning a substantial amount of capital to shareholders through dividends and share purchases. In 2022, we reinforced this commitment by initiating a shareholder return model, which is further discussed below, designed to take advantage of our low decline rates and strong visibility into our cost structure to maximize total shareholder value. Under this well-defined shareholder return model, we have declared variable dividends of$1.10 per share in aggregate based on our Discretionary Free Cash Flow (defined and discussed below) generated in the first three quarters of 2022. We have also declared fixed dividends of$0.24 during 2022. Since our 23 -------------------------------------------------------------------------------- Table of Content s 2018 IPO, we will have returned$282 million to our shareholders, which represents 256% of our IPO proceeds, consisting of$188 million paid in fixed and variable dividends and$94 million to repurchase 9.5 million shares representing 12% of our outstanding shares as ofSeptember 30, 2022 . As referenced above, our shareholder return model went into effectJanuary 1, 2022 . Like our business model, this shareholder return model is simple and further demonstrates our commitment to maximize total shareholder value. The model is based on our Discretionary Free Cash Flow, which is defined as cash flow from operations less regular fixed dividends and the capital needed to hold oil and gas production flat, and provides for the allocation of Discretionary Free Cash Flow on a quarterly basis as follows: (a) 60% predominantly in the form of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; (b) 40% in the form of discretionary capital, to be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Discretionary Free Cash Flow is a non-GAAP financial measure used by management, 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. 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. 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 advocate a co-existence between renewable and conventional energy, committed to being part of the energy transition solution by continuing to provide safe and affordable energy to our communities.
How We Plan and Evaluate Operations
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 and to net cash provided by operating activities, our most directly comparable financial 24
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measures calculated and presented in accordance with GAAP. This supplemental non-GAAP financial measure is used by management, as well as by external users of our financial statements.
Shareholder Returns
As discussed in "Management's Discussion and Analysis-Our Company," commencing in 2022, we implemented a shareholder return model based on our Discretionary Free Cash Flow, which is a non-GAAP measure that we define as cash flow from operations less regular fixed dividends and the capital needed to hold production flat year-over-year (see "Management's Discussion and Analysis-Non-GAAP Financial Measures" for reconciliation of Discretionary Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP). Under the shareholder return model, we intend to allocate a significant portion of the Discretionary Free Cash Flow generated each quarter to pay variable quarterly cash dividends, with the remaining Discretionary Free Cash Flow expected to be allocated to fund opportunistic debt repurchases, opportunistic growth (including from our extensive inventory of drilling opportunities), advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Our focus on shareholder returns is also demonstrated through our performance-based restricted stock awards, which include performance metrics based on the Company's average cash returned on invested capital and total stockholder return on both a relative and absolute basis. Our 2022 short-term incentive plan also includes Discretionary Free Cash Flow performance goals.
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 ourCalifornia steam operations with gas hedges, as well as contracts for the transportation of fuel gas from the Rockies which has historically been cheaper than theCalifornia 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 25
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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 historically 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
We consistently monitor our well servicing and abandonment operations performance with revenue and cost by service and customer, as well as Adjusted EBITDA for this business.
Business Environment, Market Conditions and Outlook
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 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 almost$128 per bbl during 2022, primarily due to global supply and demand imbalances. Brent prices were 13% lower and 33% higher for the three months endedSeptember 30, 2022 as compared to the three months endedJune 30, 2022 andSeptember 30, 2021 , respectively. Currently, global oil inventories are low relative to historical levels and supply 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. InOctober 2022 , OPEC+ determined to reduce production beginning inNovember 2022 throughDecember 2023 by 2 million bbls per day, 26
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due to the uncertainty surrounding the global economic and oil market outlooks. Furthermore, sanctions and import bans on Russian oil have been implemented by various countries in response to the war inUkraine , 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 decrease or increase with any changes in demand due to, among other things, uncertainty and volatility from global supply chain disruptions attributable to the pandemic, the ongoing conflict inUkraine , 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 Brent oil prices, as noted below, decreased by$14.28 , or 13% for the three months endedSeptember 30, 2022 compared to the three months endedJune 30, 2022 and increased by$24.47 , or 33% compared to the three months endedSeptember 30, 2021 . Though theCalifornia 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. For ourCalifornia steam operations, the price we pay for fuel gas purchases is generally based on theKern , Delivered Index for the purchases made inCalifornia and based on the Northwest, Rocky Mountains Index for the purchases made in the Rockies. The high price from these indices was$15.96 per mmbtu and the low was$5.38 per mmbtu during the third quarter of 2022, while we paid an average of$8.16 per mmbtu in this period. The price we paid on average increased by$0.86 per mmbtu, or 12% for the three months endedSeptember 30, 2022 compared to the three months endedJune 30, 2022 . The following table presents the average Brent, WTI,Kern , Delivered, Northwest,Rocky Mountains , andHenry Hub prices for the three months endedSeptember 30, 2022 ,June 30, 2022 andSeptember 30, 2021 and for the nine months endedSeptember 30, 2022 andSeptember 30, 2021 : Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2022 2022 2021 2022 2021 Oil (bbl) - Brent$ 97.70 $ 111.98 $ 73.23 $ 102.48 $ 67.97 Oil (bbl) - WTI$ 91.96 $ 108.71 $ 70.63 $ 98.39 $ 64.87 Natural gas (mmbtu) - Kern, $ 8.74$ 7.36
$ 5.75 $ 6.99 $ 5.65
Delivered
Natural gas (mmbtu) - Northwest, $ 7.79
$ 3.97 $ 6.75 $ 3.23
Rocky Mountains
Natural gas (mmbtu) -
$ 4.35 $ 6.74 $ 3.61
As mentioned above,California oil prices are Brent-influenced asCalifornia 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, 27
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should continue to allow us to realize positive cash margins in
Utah oil prices have historically traded at a discount to WTI as the local refineries are designed forUtah'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 ourCalifornia steamfloods and cogeneration facilities than we produce and sell in the Rockies. In recent history, theCalifornia gas markets have generally had higher gas prices than the Rockies and the rest ofthe 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 inCalifornia that help reduce our exposure to fuel gas purchase price fluctuations. Additionally, the negative impact of higher gas prices on ourCalifornia 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 inDecember 2023 throughDecember 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, andCalifornia , where most of our operations and assets are located, is one of the most heavily regulated states inthe 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 inCalifornia . Collectively, the effect of the existing laws and regulations is to 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, including through a restrictive and burdensome permitting and approval process, and regulate the amount of oil and natural gas that we can produce from our wells, potentially reducing below levels that would otherwise be possible. Additionally, the regulatory burden on the industry in the past has and in the future could result in increased 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 also 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. Our operations inCalifornia are particularly exposed to increased regulatory risks given the stringent environmental regulations imposed on the oil and gas industry, and current political and social trends inCalifornia continue to increase limitations on and impose additional permitting, mitigation, and emission control obligations, amongst others, upon the oil and gas industry. We cannot predict what new environmental laws or regulationsCalifornia may impose upon our operations in the future; however, any such future laws or regulations 28
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could materially and adversely impact our business and results of operations. For additional information about the potential impact that government regulations, including those regarding environmental matters, may have upon our business, operations, capital expenditures, earnings and competitive position, please see Part I, Item 1 "Regulatory Matters," as well as Part I, Item 1A. "Risk Factors" in our Annual Report. Our oil and gas operations inCalifornia are subject to compliance with the California Environmental Quality Act ("CEQA"), and we cannot receive certain permits and other approvals required for our operations until we have demonstrated compliance with CEQA. There have been a number of developments at both theCalifornia state and local levels that have resulted in delays in the issuance of new drilling permits for oil and gas activities inKern County where all of ourCalifornia assets are located, as well as a more time- and cost- intensive permitting process. Most notably, inKern County , we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (an "EIR") covering oil and gas operations inKern County ("Kern County EIR"). In 2020, a lawsuit was filed challenging the Kern County EIR, and subsequently theCalifornia Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR untilKern County made certain revisions to the Kern County EIR and recertified it ("Kern County Ruling"). To address the Kern County Ruling,Kern County prepared a supplemental EIR which was approved by theKern County Board of Supervisors inMarch 2021 . Following further challenges by plaintiffs, aKern County Superior Court judge suspended use of the Kern County EIR as supplemented, stopping the issuance of new oil and gas permits byKern County inOctober 2021 (the "Kern County Permit Suspension"), pending a determination by theKern County Superior Court that the Kern County EIR complied with the CEQA requirements. InJune 2022 , theKern County Superior Court ruled in favor ofKern County in part but also found that the supplemental Kern County EIR still failed to meet the minimum requirements of CEQA. InAugust 2022 , theKern County Board of Supervisors approved changes which addressed four discrete issues identified by the court in itsJune 2022 ruling. Following a hearing inSeptember 2022 , theKern County Superior Court subsequently issued a ruling inOctober 2022 determining that theKern County supplemental EIR was not decertified, but orderedKern County to address the four discrete issues previously identified before the Kern County Permit Suspension could be lifted. These four discrete issues included requirements for the removal of offsite legacy equipment to mitigate agricultural land use impacts, revising emissions reduction requirements to address particulate matter, the establishment of a drinking water grant fund for disadvantaged communities inKern County , and updating the local oil and gas ordinance to reflect these requirements.Kern County filed notice with the court of the changes onOctober 12, 2022 . However, the plaintiffs have objected to the adequacy ofKern County's changes and a final decision from theKern County Superior Court remains pending. Although we are cautiously optimistic that this matter will be favorably resolved in the near term, at this time, we cannot predict the timing of theKern County Superior Court's ruling nor the outcome, including the extent to which the expected or other new additional requirements incorporated into the supplemental Kern County EIR may impact our business, financial condition, results of operation and future prospects. Importantly, neither the Kern County Ruling nor the Kern County Permit Suspension invalidated existing permits and, in part due to our contingency planning efforts, our operations have not been materially impacted to date. UntilKern County is able to resume the ability to issue permits, our ability to obtain new permits and approvals to enable our future plans inKern County requires demonstrating compliance with CEQA to CalGEM. We were able to secure some new drill permits from CalGEM in specific operational areas where the CEQA environmental analyses had already been completed by a predecessor entity, which CalGEM recognized as satisfying the CEQA compliance obligation. Demonstrating CEQA compliance without being able to reference the Kern County EIR (which we cannot currently do due to the Kern County Permit Suspension) or another CEQA-compliant environmental analysis 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 of the Kern County Permit Suspension, we together with otherKern County operators have experienced significant delays in the issuance of permits for new wells by CalGEM, in part due to the more intensive permitting process and CEQA compliance requirements for new wells, which we expect will continue to be the case until the Kern County Permit Suspension is resolved. We have submitted applications for additional permits that we believe, if received on a timely basis together with the permits already received, would enable us to execute our currently anticipated 2023 drilling program. However, there is no assurance that such additional permits will be approved in a timely manner or at all, even if the Kern County Permit Suspension is lifted. Fortunately, we have not experienced delays in the issuance of permits for the workover or recompletion of existing wells or other activities re-using existing well bores, for which the environmental review is 29
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expedited because the well already exists and the environmental impact analysis is simpler to conduct.
We timely submitted permit applications for the new wells contemplated by our 2022 capital development. However, due to the delays in permit issuance discussed above and insufficient permit inventory, beginning in the second quarter the execution of our remaining 2022 capital development program ultimately required an increase in workovers, recompletions and other activities re-using existing well bores and deployment of techniques to increase production from existing producing wells (referred to as our "base production"), and decrease in the number of new wells drilled inCalifornia contemplated by our initial program. Our plans for the remainder of the year will depend on whether and when we receive permits to drill new wells, as well as other key approvals (such as UIC permits to support water disposal) required to support planned activities. If we are unable to timely obtain those permits or approvals, our planned 2022 production could be adversely impacted and we may need to further modify our 2022 capital development program and alter our planned capital expenditures or deploy that capital to other activities. However, at this time we do not expect our planned 2022 production or results of operations to be materially impacted even if we are unable to timely obtain those permits and approvals because we currently believe we can continue to offset production from planned new wells with increased production from workover and other activities re-using existing well bores, as well as from our base production through field optimization initiatives. At this time we expect that approximately 94% of our planned 2022 production will come from our base production, with the remainder from workovers and other activities related to existing well bores, as well as from new wells drilled during the year. Separately, onSeptember 16, 2022 , the Governor ofCalifornia signed into law Senate Bill No. 1137 which establishes 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as homes, schools or parks effectiveJanuary 1, 2023 . Additional provisions, among others, imposed EH&S controls applicable to wells located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at production facilities determined not to be in compliance with certain air emission requirements. These additional provisions are effectiveJanuary 1, 2025 . We are currently evaluating the impact of Senate Bill No. 1137 on our assets (specifically including reserves) and development plans while actively pursuing mitigation efforts with respect to the potential impacts on current and planned wells. Additionally,President Biden signed the Inflation Reduction Act ("IRA") into law onAugust 16, 2022 which, among other provisions, imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector. Beginning in 2024, the IRA's methane emissions charge imposes a fee on excess methane emissions from certain oil and gas facilities, starting at$900 per metric ton of leaked methane in 2024 and rising to$1,200 in 2025, and$1,500 in 2026 and thereafter. The imposition of this fee and other provisions of the IRA could increase our operating costs and accelerate the transition away from oil and gas, which could adversely affect our business and results of operations.
Inflation
TheU.S. inflation rate has been steadily increasing since 2021 and throughout 2022. These inflationary pressures have resulted in and may result in additional increases to the costs of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused theU.S. Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which-or the combination thereof-could adversely affect our business and results of operations.
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 inUtah , by electrical storms and high temperatures in the spring and summer, and by wild fires and rain. 30
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Natural gas prices fluctuate based on seasonal and other market-related impacts. For example, natural gas prices increased significantly during the first three 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 byRussia , as well as lower storage levels and damage to theNord Stream pipeline connectingRussia to the rest ofEurope for gas supplies. 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 inCalifornia to help limit our exposure to fuel gas purchase price fluctuations.
Capital Expenditures
For the three and nine months endedSeptember 30, 2022 , our consolidated capital expenditures were approximately$41 million and$103 million , respectively, on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement spending. Approximately 47% and 42% of capital expenditures for the nine months endedSeptember 30, 2022 was directed toCalifornia oil andUtah operations, respectively. Our budget for 2022 capital expenditures for D&P operations and corporate activities was approximately$125 to$135 million , excluding$8 million for CJWS, the planned use of which was expected to keep our annual production relatively flat to 2021 after taking into account the impact of acquisitions and divestitures completed in late 2021 and early 2022. Based on activity to date and expected for the remainder of 2022, we currently anticipate our full year capital expenditures will be slightly more than our initial budget and will be between$140 and$145 million . We have adjusted our plannedCalifornia capital program in late 2022 based on the success of recent development activity. To keep up the momentum into 2023, we are accelerating our development program during the fourth quarter of 2022. Additionally, due to the results achieved from mid-year workover and recompletion activity inUtah , we allocated incremental funding to perform additional workovers inUtah . The increase in full-year capital expenditures is also partially due to cost inflation in excess of our initial expectations, which we began to experience mid-year. 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 inCalifornia , 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$5 million and$16 million for plugging and abandonment activities in the three months and nine months endedSeptember 30, 2022 , respectively. Our well servicing and abandonment segment expects to plug and abandon approximately 2,500 to 3,000 wells for their third-party customers in 2022, helping to safely address the environmental hazards and other risks fromCalifornia's number of idle wells. In the nine months endedSeptember 30, 2022 , our wells servicing and abandonment segment plugged and abandoned 2,100 wells for third-party customers. 31
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Summary by Area
The following table shows a summary by area of our selected historical financial and operating information for our development and production operations for the periods indicated.California (San
Joaquin and
Three Months Ended
September 30, 2022
($ in thousands, except prices) Oil, natural gas and natural gas liquids sales$ 175,245 $ 204,706 $ 140,160 Operating income(1) $ 57,864$ 63,608 $ 26,652 Depreciation, depletion, and amortization (DD&A) $ 33,979
Average daily production (mboe/d) 20.8 21.0 21.8 Production (oil % of total) 100 % 100 % 100 % Realized sales prices: Oil (per bbl) $ 91.67$ 107.31 $ 69.92 NGLs (per bbl) $ - $ - $ - Gas (per mcf) $ - $ - $ - Capital expenditures(2) $ 15,220$ 18,672 $ 29,806 Utah Colorado (Uinta basin) (Piceance basin)(4) Three Months Ended Three Months Ended September 30, June 30, September 30, September 30, June 30, September 30, 2022 2022 2021 2022 2022 2021
($ in thousands, except
prices)
Oil, natural gas and natural gas liquids sales$ 28,323 $ 35,338 $ 18,118 $ - $ -$ 2,779 Operating income(1)$ 11,123 $ 20,579 $ 7,246 $ - $ -$ 2,360 Depreciation, depletion, and amortization (DD&A)$ 2,278 $ 964 $ 611 $ - $ - $ 38 Average daily production (mboe/d) 5.0 5.2 4.4 - - 1.2 Production (oil % of total) 57 % 57 % 50 % - % - % 1 % Realized sales prices: Oil (per bbl)$ 73.83 $ 94.47 $ 60.09 $ - $ -$ 66.97 NGLs (per bbl)$ 40.72 $ 56.47 $ 40.88 $ - $ - $ - Gas (per mcf)$ 7.95 $ 7.35 $ 4.31 $ - $ -$ 4.24 Capital expenditures(2)$ 21,196 $ 11,563 $ 5,728 $ - $ - $ - __________ (1) Operating income (loss) includes oil, natural gas and NGL sales, marketing revenues, other revenues, and scheduled oil derivative settlements, offset by operating expenses (as defined elsewhere), general and administrative expenses, DD&A, impairment of oil and gas properties, and taxes, other than income taxes.
(2) Excludes corporate capital expenditures.
(3) Our Placerita properties, in the
(4) Our properties in
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Production and Prices
The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.
Three Months Ended
September 30, 2022 June 30, 2022 September 30, 2021 Average daily production:(1) Oil (mbbl/d) 23.7 24.0 24.1 Natural Gas (mmcf/d) 10.4 11.0 17.6 NGL (mbbl/d) 0.4 0.4 0.4 Total (mboe/d)(2) 25.8 26.2 27.4 Total Production: Oil (mbbl) 2,171 2,182 2,211 Natural gas (mmcf) 953 999 1,615 NGLs (mbbl) 39 37 39 Total (mboe)(2) 2,369 2,386 2,519 Weighted-average realized sales prices: Oil without hedges ($/bbl) $ 89.54$ 105.70 $ 69.01 Effects of scheduled derivative settlements ($/bbl) $ (13.13)$ (21.92) $ (14.66) Oil with hedges ($/bbl) $ 76.41$ 83.78 $ 54.35 Natural gas ($/mcf) $ 7.95 $ 7.35 $ 4.29 NGL ($/bbl) $ 40.72$ 56.47 $ 40.88 Average Benchmark prices: Oil (bbl) - Brent $ 97.70$ 111.98 $ 73.23 Oil (bbl) - WTI $ 91.96$ 108.71 $ 70.63 Natural gas (mmbtu) - Kern, Delivered(3) $ 8.74 $ 7.36 $ 5.75 Natural gas (mmbtu) - Northwest, Rocky $ 7.79 $ 6.69 $ 3.97
Mountains
Natural gas (mmbtu) - Henry Hub(4) $ 8.03 $ 7.50 $ 4.35 __________
(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
(2) Natural gas volumes have been converted to boe based on energy content of six mcf of gas to one bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the three months endedSeptember 30, 2022 , the average prices of Brent oil andHenry Hub natural gas were$97.70 per bbl and$8.03 per mmbtu.
(3)
(4)
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The following table sets forth average daily production by operating area for the periods indicated: Three Months Ended September 30, 2022 June 30, 2022 September 30, 2021 Average daily production (mboe/d):(1) California(2) 20.8 21.0 21.8 Utah 5.0 5.2 4.4 Colorado(3) - - 1.2 Total average daily production 25.8 26.2 27.4 __________
(1) Production represents volumes sold during the period.
(2) In
(3) In
On a sequential basis, our average daily production decreased by 0.4 mboe/d for the three months endedSeptember 30, 2022 , compared to the second quarter 2022. OurCalifornia production was 20.8 mboe/d for the third quarter of 2022, a decrease of 0.2 mboe/d from the second quarter 2022, which was largely due to fewer new wells added in the third quarter than in the second quarter, partially offset by workovers and other activities re-using existing well bores. OurUtah production decreased largely due to fewer wells completed and placed on production in the third quarter than in the second quarter. Average daily production for the three months endedSeptember 30, 2021 included properties that have since been divested, specifically, Placerita properties inCalifornia and Piceance properties inColorado , which were our only assets inColorado . The combined production from these properties was 2.0 mboe/d in the third quarter 2021 (1.2 mboe/d inColorado and 0.8 mboe/d inCalifornia ) and there was no production from these properties in the second and third quarters of 2022. Average daily production inCalifornia for the three months endedSeptember 30, 2022 decreased 0.2 mboe/d compared to the same period in 2021, when excluding the production from the Placerita properties for 2021. The decrease was due to decreased development activity inCalifornia during 2022. The year-over-year increase in theUtah production was driven by the addition of theAntelope Creek properties we acquired inFebruary 2022 . 34
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The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.
Nine Months Ended
September 30, 2022 September 30, 2021 Average daily production:(1) Oil (mbbl/d) 24.0 24.0 Natural Gas (mmcf/d) 11.0 17.3 NGL (mbbl/d) 0.4 0.4 Total (mboe/d)(2) 26.2 27.3 Total Production: Oil (mbbl) 6,551 6,545 Natural gas (mmcf) 2,990 4,728 NGLs (mbbl) 111 105 Total (mboe)(2) 7,160 7,438 Weighted-average realized sales prices: Oil without hedges ($/bbl) $ 95.83 $ 63.59 Effects of scheduled derivative settlements ($/bbl) $ (16.81) $ (15.03) Oil with hedges ($/bbl) $ 79.02 $ 48.56 Natural gas ($/mcf) $ 6.99 $ 5.16 NGL ($/bbl) $ 47.98 $ 32.97 Average Benchmark prices: Oil (bbl) - Brent $ 102.48 $ 67.97 Oil (bbl) - WTI $ 98.39 $ 64.87 Gas (mmbtu) - Kern, Delivered(3) $ 6.99 $ 5.65 Natural gas (mmbtu) - Northwest, Rocky Mountains $ 6.75 $ 3.23 Natural gas (mmbtu) - Henry Hub(4) $ 6.74 $ 3.61 __________
(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
(2) Natural gas volumes have been converted to boe based on energy content of six mcf of gas to one bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, during the nine months endedSeptember 30, 2022 , the average prices of Brent oil andHenry Hub natural gas were$102.48 per bbl and$6.74 per mmbtu respectively.
(3)
(4)Henry Hub is the relevant index used for gas sales in the Rockies. 35
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The following table sets forth average daily production by operating area for the periods indicated: Nine Months Ended September 30, 2022 September 30, 2021 Average daily production (mboe/d):(1) California(2) 21.3 21.8 Utah 4.8 4.3 Colorado(3) 0.1 1.2 Total average daily production 26.2 27.3 __________
(1) Production represents volumes sold during the period.
(2) In
(3) In
Average daily production for the nine months endedSeptember 30, 2022 included 0.9 mboe/d of production from theAntelope Creek (Utah ) asset acquired in the first quarter of 2022 and 0.1 mboe/d of production from the Piceance (Colorado ) asset, which was divested in the first quarter of 2022. The nine months endedSeptember 30, 2021 included 1.2 mboe/d of production from theColorado assets, as well as 0.8 mboe/d of production from the Placerita asset inCalifornia , which was divested in the fourth quarter of 2021. On a comparable basis, when excluding the volumes from these acquisitions and divestitures,California produced 21.3 mboe/d for the nine months endedSeptember 30, 2022 , a 0.3 mboe/d increase when compared to the nine months endedSeptember 30, 2021 . When excluding the volumes from these transactions, our total production was essentially flat for the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 . We drilled 51 wells inCalifornia in the first nine months of 2022, of which 39 were producing wells, eight were delineation wells and four were observation wells. We also drilled 12 wells in Uinta, all of which were producing wells. 36
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Results of Operations
Three Months EndedSeptember 30, 2022 compared to Three Months EndedJune 30, 2022 . Three Months Ended September 30, 2022 June 30, 2022 $ Change % Change (in thousands) Revenues and other: Oil, natural gas and NGL sales$ 203,585 $ 240,071 $ (36,486) (15) % Service revenue 48,594 46,178 2,416 5 % Electricity sales 9,711 7,419 2,292 31 % Gain (losses) on oil and gas sales derivatives 114,279 (40,658) 154,937 n/a Marketing and other revenues 277 120 157 131 % Total revenues and other$ 376,446 $ 253,130 $ 123,316 49 % Revenues and Other Oil, natural gas and NGL sales decreased by$36 million , or 15%, to approximately$204 million for the three months endedSeptember 30, 2022 , compared to the three months endedJune 30, 2022 . The decrease was driven by$35 million lower unhedged oil prices, including the approximate$2 per bbl impact from discounts applied to approximately 25% of third quarterCalifornia volumes due to an unexpected third-party pipeline outage for unplanned repairs during most of the third quarter of 2022, as well as$1 million decrease due to lower oil volumes. The unplanned repairs on the pipeline are ongoing and the Company currently expects the outage to extend into the first quarter of 2023, which may require additional volumes to be sold at a discount until resolved. Service revenue consisted entirely of revenue from the well servicing and abandonment business. Service revenue increased by$2 million or 5% to approximately$49 million in the third quarter 2022, due to increased activity, which is partially seasonal, and rate increases effective late second quarter to offset a portion of cost inflation. Electricity sales represent sales to utilities and increased$2 million , or 31%, to approximately$10 million for the three months endedSeptember 30, 2022 compared to the three months endedJune 30, 2022 . This increase was largely due to higher unit sales prices driven by higher natural gas prices. Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement loss for the three months endedSeptember 30, 2022 was$29 million and the loss for the three months endedJune 30, 2022 was$48 million . The quarter-over-quarter decrease in settlement losses was driven by an approximately$14 per bbl decline in index prices. The mark-to-market non-cash gain was$143 million and$7 million for the three months endedSeptember 30, 2022 andJune 30, 2022 , respectively, due to a narrower spread between future market prices and the fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses). Marketing and other revenues, which included third-party marketing activities, were not material for the three months endedSeptember 30, 2022 andJune 30, 2022 . 37
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Table of Contents Three Months Ended September 30, 2022 June 30, 2022 $ Change % Change (in thousands, except expenses per boe) Expenses and other: Lease operating expenses$ 79,141 $ 72,455 $ 6,686 9 % Costs of services 37,628 36,709 919 3 % Electricity generation expenses 6,055 6,122 (67) (1) % Transportation expenses 1,277 1,108 169 15 % General and administrative expenses 23,388 23,183 205 1 % Depreciation, depletion and 39,506
38,055
amortization 1,451 4 % Taxes, other than income taxes 7,335 11,214 (3,879) (35) % (Gains) losses on natural gas purchase derivatives (28,942) 10,661 (39,603) n/a Other operating expenses 623 353 270 76 % Total expenses and other 166,011 199,860 (33,849) (17) % Other (expenses) income: Interest expense (7,867) (7,729) (138) 2 % Other, net (24) (42) 18 (43) % Total other (expenses) income (7,891) (7,771) (120) 2 % Income before income taxes 202,544 45,499 157,045 345 % Income tax expense 10,884 2,145 8,739 407 % Net income$ 191,660 $ 43,354 $ 148,306 342 % Expenses per boe:(1) Lease operating expenses $ 33.40$ 30.37 $ 3.03 10 % Electricity generation expenses 2.56 2.57 (0.01) - % Electricity sales(1) (4.10) (3.11) (0.99) 32 % Transportation expenses 0.54 0.46 0.08 17 % Transportation sales(1) (0.12) (0.05) (0.07) 140 % Derivatives settlements received for gas purchases(1) (5.82) (4.27) (1.55) 36 % Total operating expenses $ 26.46$ 25.97 $ 0.49 2 % Total unhedged operating expenses(2) $ 32.28$ 30.24 $ 2.04 7 % Total non-energy operating expenses(3) $ 17.59$ 16.10 $ 1.49 9 % Total energy operating expenses(4) $ 8.87 $ 9.87$ (1.00) (10) % General and administrative expenses(5) $ 9.87 $ 9.72$ 0.15 2 % Depreciation, depletion and $ 16.67$ 15.95 amortization$ 0.72 5 % Taxes, other than income taxes $ 3.10 $ 4.70$ (1.60) (34) % __________ (1) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also include the effect of derivative settlements (received or paid) for gas purchases. 38
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(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately$1.81 per boe and$1.77 per boe for the three months endedSeptember 30, 2022 andJune 30, 2022 , respectively.
Expenses and Other
In accordance with GAAP, we report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues. However, these revenues are viewed and used internally in calculating operating expenses, which are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
Operating expenses are defined above in "How We Plan and Evaluate Operations", which include electricity, marketing and transportation revenues. On a hedged basis, operating expenses increased by$0.49 per boe, or 2%, to$26.46 for the third quarter of 2022 compared to the second quarter of 2022. During the third quarter, non-energy operating expenses increased$1.49 per boe due to higher seasonal power rates and other field operating costs. A portion of the increased costs in non-energy operating expenses were driven by inflation. Energy operating expense decreased$1.00 per boe in the third quarter compared to the second quarter of 2022 due to higher electricity sales. Higher gas purchase settlements mitigated the impact of higher purchase prices. Unhedged lease operating expenses per boe increased by 10%, or$3.03 , to$33.40 for the three months endedSeptember 30, 2022 , compared to$30.37 per boe for the three months endedJune 30, 2022 , generally for the same reasons noted above for non-energy expense. Unhedged average fuel purchase price per mmbtu increased 12% while consumption declined 3% in the third quarter compared to the second quarter, which when combined resulted in a$1.09 per boe higher unhedged higher fuel costs for ourCalifornia steam operations. Cost of services in 2022 consisted entirely of costs from the well servicing and abandonment business. Cost of services increased by$1 million , or 3%, to$38 million in the third quarter of 2022, mainly due to higher activity, which is partially driven by a seasonal impact. Electricity generation expenses were relatively flat at$2.56 per boe for the three months endedSeptember 30, 2022 , compared to$2.57 per boe for the three months endedJune 30, 2022 . Gains and losses on natural gas purchase derivatives resulted in a$29 million gain for the three months endedSeptember 30, 2022 and a loss of$11 million in the three months endedJune 30, 2022 . Settlement gains for the three months endedSeptember 30, 2022 andJune 30, 2022 were$14 million , or$5.82 per boe, and$10 million , or$4.27 per boe, respectively, and increased due to higher index prices relative to the derivative fixed prices of settled positions in the third quarter of 2022 compared to the second quarter. The mark-to-market valuation gain was$15 million for the three months endedSeptember 30, 2022 and a loss of$21 million for the three months endedJune 30, 2022 . Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).
Transportation expenses were comparable for the periods presented.
General and administrative expenses were flat at$23 million for the three months endedSeptember 30, 2022 and the three months endedJune 30, 2022 . For the three months endedSeptember 30, 2022 andJune 30, 2022 , general and administrative expenses included non-cash stock compensation costs of approximately$4.3 million . We incurred no non-recurring costs for the three months endedSeptember 30, 2022 andJune 30, 2022 . Less than 10% of our overhead is capitalized and thus excluded from general and administrative expenses.
Adjusted general and administrative expenses, which exclude non-cash stock
compensation costs and non-recurring costs, were
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calculated and presented in accordance with GAAP.
DD&A increased 4% to$40 million for the three months endedSeptember 30, 2022 compared to the three months endedJune 30, 2022 . The increase was driven by the mix of production in the D&P segment.
Taxes, Other Than Income Taxes
Three Months Ended September 30, 2022 June 30, 2022 $ Change % Change (per boe) Severance taxes$ 1.45 $ 1.54$ (0.09) (6) % Ad valorem and property taxes 1.48 1.49 (0.01) (1) % Greenhouse gas allowances 0.17 1.67 (1.50) (90) % Total taxes other than income taxes$ 3.10 $ 4.70$ (1.60) (34) % Taxes, other than income taxes, decreased in the three months endedSeptember 30, 2022 by$1.60 per boe, or 34%, to$3.10 . The reduction in third quarter 2022 greenhouse gas ("GHG") costs was a result of lower mark-to-market prices compared to the second quarter of 2022. Severance taxes were lower in the third quarter of 2022 due to lower revenue.
Other Operating Expenses
Other operating expenses were comparable for periods presented.
Interest Expense
Interest expense was relatively flat at
Income Taxes
Our effective tax rate was comparable at approximately 5% for the three months
ended
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Three Months EndedSeptember 30, 2022 compared to Three Months EndedSeptember 30, 2021 . Three Months Ended September 30, 2022 2021 $ Change % Change (in thousands) Revenues and other: Oil, natural gas and NGL sales$ 203,585 $ 161,058 $ 42,527 26 % Service revenue 48,594 - 48,594 100 % Electricity sales 9,711 12,371 (2,660) (22) % Gains (losses) on oil and gas sales derivatives 114,279 (30,864) 145,143 n/a Marketing and other revenues 277 849 (572) (67) % Total revenues and other$ 376,446 $ 143,414 $ 233,032 162 % Revenues and Other
Oil, natural gas and NGL sales increased by
Service revenue in the third quarter 2022 was
Electricity sales represent sales to utilities, and decreased by approximately$3 million , or 22%, to approximately$10 million for the three months endedSeptember 30, 2022 when compared to the three months endedSeptember 30, 2021 . The decrease was largely due to lower unit sales volumes driven by the sale of our Placerita asset, which included our largest electricity-generating cogeneration facility ("cogen"), in the fourth quarter 2021. For the three years prior to divestiture the Placerita cogen accounted for approximately 41% of our electrical sales. Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement losses for the three months endedSeptember 30, 2022 and the three months endedSeptember 30, 2021 were$29 million and$32 million , respectively. The quarter-over-quarter decrease in settlement losses were driven by lower oil prices relative to our derivative fixed prices in the third quarter of 2022 than that of the same period in 2021. Notional volumes were 15 mbbl/d in the third quarter 2022 and 14 mbbls/d in the third quarter 2021. The mark-to-market non-cash gain was$143 million and$1 million for the three months endedSeptember 30, 2022 andSeptember 30, 2021 , respectively, due to a narrower spread between future market prices and the fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses).
Marketing and other revenues were not material for the three months ended
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Table of Contents Three Months Ended September 30, 2022 2021 $ Change % Change (in thousands, except expenses per boe) Expenses and other: Lease operating expenses$ 79,141 $ 60,930 $ 18,211 30 % Costs of services 37,628 - 37,628 100 % Electricity generation expenses 6,055 7,128 (1,073) (15) % Transportation expenses 1,277 1,806 (529) (29) % Marketing expenses - 715 (715) (100) % General and administrative expenses 23,388 17,614 5,774 33 % Depreciation, depletion and 39,506 35,902 10 % amortization 3,604 Taxes, other than income taxes 7,335 13,420 (6,085) (45) % Gains on natural gas purchase derivatives (28,942) (14,980) (13,962) 93 % Other operating expenses 623 3,986 (3,363) (84) % Total expenses and other 166,011 126,521 39,490 31 % Other (expenses) income: Interest expense (7,867) (7,810) (57) 1 % Other, net (24) (5) (19) 380 % Total other (expenses) income (7,891) (7,815) (76) 1 % Income before income taxes 202,544 9,078 193,466 2,131 % Income tax expense (benefit) 10,884 (758) 11,642 (1,536) % Net income$ 191,660 $ 9,836 $ 181,824 (1,849) % Expenses per boe:(1) Lease operating expenses $ 33.40$ 24.20 $ 9.20 38 % Electricity generation expenses 2.56 2.83 (0.27) (10) % Electricity sales(1) (4.10) (4.91) 0.81 (16) % Transportation expenses 0.54 0.72 (0.18) (25) % Transportation sales(1) (0.12) (0.05) (0.07) 140 % Marketing expenses - 0.28 (0.28) (100) % Marketing revenues(1) - (0.29) 0.29 (100) % Derivatives settlements received for 4 % gas purchases(1) (5.82) (5.60) (0.22) Total operating expenses $ 26.46$ 17.18 $ 9.28 54 %
Total unhedged operating expenses(2) $ 32.28
42 %
Total non-energy operating expenses(3) $ 17.59
29 %
Total energy operating expenses(4) $ 8.87
147 %
General and administrative expenses(5) $ 9.87
41 % Depreciation, depletion and $ 16.67$ 14.25 $ 2.42 17 %
amortization
Taxes, other than income taxes $ 3.10$ 5.33 $ (2.23) (42) % __________ 42
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(1) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also include the effect of derivative settlements (received or paid) for gas purchases.
(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately$1.81 per boe and$1.66 per boe for the three months endedSeptember 30, 2022 andSeptember 30, 2021 , respectively.
Expenses and Other
On a hedged basis, operating expenses, increased by 54%, or$9.28 per boe, to$26.46 per boe for the third quarter of 2022 compared to$17.18 per boe for the third quarter of 2021. This increase was due to higher energy operating expense of$5.28 per boe and non-energy operating expense of$4.00 per boe. Energy operating expense increased largely due to higher hedged natural gas purchase prices. Non-energy operating expense increased due to higher power rates and other field operating costs. A portion of the increased costs in non-energy operating expenses were driven by inflation. Unhedged lease operating expenses were$33.40 per boe for the three months endedSeptember 30, 2022 , a 38% or$9.20 per boe increase compared to$24.20 for the three months endedSeptember 30, 2021 . Unhedged fuel costs for ourCalifornia steam operations increased$4.97 per boe. Unhedged average fuel purchase price per mmbtu increased 41% in the third quarter of 2022 compared to the third quarter of 2021 and gas volumes purchased were down 11%. Non-fuel lease operating expense increased$4.23 per boe, generally for the same reasons noted above for non-energy operating expense.
Cost of services in the third quarter of 2022 were
Electricity generation expenses decreased approximately 10% to$2.56 per boe for the three months endedSeptember 30, 2022 from$2.83 per boe for the same period in 2021 due to the Placerita properties sale, partially offset by higher natural gas costs. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements. Gains and losses on natural gas purchase derivatives for the three months endedSeptember 30, 2022 andSeptember 30, 2021 resulted in a gain of$29 million and$15 million , respectively. Settlement gains for the three months endedSeptember 30, 2022 andSeptember 30, 2021 were$14 million in each period, or$5.82 per boe and$5.60 per boe, respectively. The mark-to-market non-cash gain was$15 million and$1 million for the three months endedSeptember 30, 2022 andSeptember 30, 2021 , respectively, due to a larger spread between future market prices and the derivative fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses). Transportation expenses decreased to$0.54 per boe for the three months endedSeptember 30, 2022 compared to$0.72 per boe for the three months endedSeptember 30, 2021 , primarily due to the sale of our Piceance operations the first quarter of 2022.
Marketing expenses were not material for the three months ended
General and administrative expenses increased$6 million , or 33%, to approximately$23 million for the three months endedSeptember 30, 2022 compared to the three months endedSeptember 30, 2021 . For the three months endedSeptember 30, 2022 andSeptember 30, 2021 , general and administrative expenses included non-cash stock 43
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compensation costs of approximately
Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, increased 46% to$19 million for the three months endedSeptember 30, 2022 compared to$13 million for the three months endedSeptember 30, 2021 . The substantial majority of the increase was due to the acquisition of CJWS, as well as higher legal and other professional service expenses and employee costs. DD&A for the third quarter of 2022 increased approximately$4 million to$40 million when compared to the third quarter of 2021 driven primarily by CJWS and slightly higher DD&A rates for the D&P segment, partially offset by lower production.
Taxes, Other Than Income Taxes
Three Months Ended September 30, 2022 2021 $ Change % Change (per boe) Severance taxes$ 1.45 $ 0.80 $ 0.65 81 % Ad valorem and property taxes 1.48 1.73 (0.25) (14) % Greenhouse gas allowances 0.17 2.80 (2.63) (94) % Total taxes other than income taxes$ 3.10 $ 5.33 $
(2.23) (42) %
Taxes, other than income taxes decreased 42% to$3.10 per boe for the three months endedSeptember 30, 2022 compared to$5.33 per boe for the three months endedSeptember 30, 2021 . Severance taxes increased due to higher production and prices inUtah , while property taxes were lower due to the divestitures of Piceance and Placerita. GHG expense was significantly lower, largely due to lower emissions which resulted from the divestiture of Placerita and its cogeneration facility, as well as lower prices.
Other Operating Expenses (Income)
Other operating expenses decreased$3 million or 84% to less than$1 million for the three months endedSeptember 30, 2022 when compared to the same quarter in 2021. The decrease is primarily due to$3 million of unamortized debt issuance costs related to the termination of the 2017 RBL facility incurred in three months endedSeptember 30, 2021 .
Interest Expense
Interest expense was comparable in the three months ended
Income Taxes Our effective tax rate was approximately 5% for the three months endedSeptember 30, 2022 compared to (8)% for the three months endedSeptember 30, 2021 . The rates were impacted by changes in the valuation allowance recorded against deferred tax assets. 44
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Nine Months EndedSeptember 30, 2022 compared to Nine Months EndedSeptember 30, 2021 . Nine Months Ended September 30, 2022 2021 $ Change % Change (in thousands) Revenues and other: Oil, natural gas and NGL sales$ 654,007 $ 444,098 $ 209,909 47 % Service revenue 134,608 - 134,608 100 % Electricity sales 22,549 29,328 (6,779) (23) % Losses on oil and gas sales derivatives (88,237) (140,021) 51,784 (37) % Marketing and other revenues 731 3,459 (2,728) (79) % Total revenues and other$ 723,658 $ 336,864 $ 386,794 115 % Revenues and Other Oil, natural gas and NGL sales increased by$210 million , or 47%, to approximately$654 million for the nine months endedSeptember 30, 2022 when compared to the nine months endedSeptember 30, 2021 . The increase was driven by higher realized prices, partially offset by pricing discounts applied to approximately 25% of third quarterCalifornia volumes due to an unexpected third party pipeline outage for unplanned repairs during most of the third quarter of 2022.
Service revenue consisted entirely of revenue from the well servicing and
abandonment business we acquired on
Electricity sales, which represent sales to utilities, decreased$7 million , or 23%, to$23 million for the nine months endedSeptember 30, 2022 when compared to the nine months endedSeptember 30, 2021 . The decrease was primarily due to lower sales volume as a result of the sale of a cogeneration facility which was part of the Placerita divestiture in late 2021. Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. We had settlement losses of$110 million and$96 million for the nine months endedSeptember 30, 2022 and the nine months endedSeptember 30, 2021 , respectively. The period over period increase in settlement losses was driven by a wider spread between the settled derivative fixed prices and index oil prices in the nine months endedSeptember 30, 2022 compared to the same period of 2021. Partially offsetting this effect, notional volumes decreased to 14 mbbl/d in the nine months endedSeptember 30, 2022 from 17 mbbl/d in the nine months endedSeptember 30, 2021 . The mark-to-market non-cash gain of$22 million for the nine months endedSeptember 30, 2022 was the result of lower futures prices relative to the derivative fixed prices. Conversely, the$44 million loss in the same period of 2021 was due to higher futures prices relative to the derivative fixed prices, as measured at the end of their respective periods. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses). Marketing and other revenues decreased approximately$3 million for the nine months endedSeptember 30, 2022 when compared to the nine months endedSeptember 30, 2021 due to the sale of our Piceance Colorado operations in the fourth quarter of 2021, which included third-party marketing activities. Piceance has historically accounted for nearly all of our marketing revenues. 45
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Table of Contents Nine Months Ended September 30, 2022 2021 $ Change % Change (in thousands, except expenses per boe) Expenses and other: Lease operating expenses$ 214,720 $ 168,756 $ 45,964 27 % Costs of services 107,809 - 107,809 100 % Electricity generation expenses 16,640 19,488 (2,848) (15) % Transportation expenses 3,543 5,139 (1,596) (31) % Marketing expenses 299 2,986 (2,687) (90) % General and administrative expenses 69,513 50,749 18,764 37 % Depreciation, depletion and 117,338 105,592 amortization 11,746 11 % Taxes, other than income taxes 25,154 34,580 (9,426) (27) % Gains on natural gas purchase derivatives (47,335) (54,349) 7,014 (13) % Other operating expenses 4,745 4,827 (82) (2) % Total expenses and other 512,426 337,768 174,658 52 % Other (expenses) income: Interest expense (23,271) (24,513) 1,242 (5) % Other, net (79) (156) 77 (49) % Total other (expenses) income (23,350) (24,669) 1,319 (5) % Income (loss) before income taxes 187,882 (25,573) 213,455 (835) % Income tax expense (benefit) 9,678 (1,206) 10,884 (902) % Net income (loss)$ 178,204 $ (24,367) $ 202,571 (831) % Expenses per boe:(1) Lease operating expenses$ 29.99 $ 22.69 $ 7.30 32 % Electricity generation expenses 2.32 2.62 (0.30) (11) % Electricity sales(1) (3.15) (3.94) 0.79 (20) % Transportation expenses 0.49 0.69 (0.20) (29) % Transportation sales(1) (0.06) (0.05) (0.01) 20 % Marketing expenses 0.04 0.40 (0.36) (90) % Marketing revenues(1) (0.04) (0.42) 0.38 (90) % Derivatives settlements received for (3.58) (5.68) 2.10 (37) % gas purchases(1) Total operating expenses$ 26.01 $ 16.31 $ 9.70 59 %
Total unhedged operating expenses(2)
$ 7.60 35 %
Total non-energy operating expenses(3)
$ 2.72 21 %
Total energy operating expenses(4)
$ 6.98 212 %
General and administrative expenses(5)
$ 2.89 42 % Depreciation, depletion and$ 16.39 $ 14.20 $ 2.19 15 %
amortization
Taxes, other than income taxes
$ (1.14) (25) % __________ 46
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(1) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also include the effect of derivative settlements (received or paid) for gas purchases.
(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately$1.71 per boe and$1.43 per boe for the nine months endedSeptember 30, 2022 andSeptember 30, 2021 , respectively.
Expenses and Other
On a hedged basis, operating expenses increased 59%, or$9.70 per boe, to$26.01 for the nine months endedSeptember 30, 2022 from$16.31 per boe for the nine months endedSeptember 30, 2021 . This increase was due to higher energy operating expense of$6.98 per boe and non-energy operating expense of$2.72 per boe. Energy operating expense increased primarily due to higher hedged purchased natural gas costs. Non-energy operating expense increased largely due to higher power rates and other lease operating expenses noted below, including inflation, in the nine months endedSeptember 30, 2022 compared to same period of 2021. Unhedged lease operating expenses were$29.99 per boe for the nine months endedSeptember 30, 2022 , a 32% or$7.30 per boe increase compared to$22.69 for the nine months endedSeptember 30, 2021 , driven by higher unhedged fuel costs for ourCalifornia steam operations. Unhedged average fuel purchase price per mmbtu increased 36% in the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 . Non-fuel lease operating expense increased$3.12 per boe in the nine months endedSeptember 30, 2022 when compared to the same period of 2021. Key increases included higher workover and field monitoring activity associated with our field optimization program, and higher well and surface facilities maintenance and power costs. A portion of these higher costs were driven by inflation.
Cost of services in 2022 consisted entirely of costs from the well servicing and
abandonment business we acquired on
Electricity generation expenses decreased approximately 11% to$2.32 per boe for the nine months endedSeptember 30, 2022 from$2.62 per boe for the same period in 2021 due to lower volumes sold resulting from the previously discussed sale of a cogeneration facility, more than offsetting the increase in fuel prices. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements. Gains and losses on natural gas purchase derivatives for the nine months endedSeptember 30, 2022 andSeptember 30, 2021 consisted of gains of$47 million and$54 million , respectively. The settlement gain for the nine months endedSeptember 30, 2022 was$26 million , or$3.58 per boe, compared to a gain of$42 million , or$5.68 per boe, for same period in 2021, driven by lower hedged volumes in 2022 compared to that of 2021. The mark-to-market valuation gain for the nine months endedSeptember 30, 2022 was$22 million compared to$12 million for the same period in 2021 due to more open notional volumes atSeptember 30, 2022 and higher futures prices relative to our derivative fixed prices compared to those atSeptember 30, 2021 . Because we are the fixed price payer on these natural gas swaps, generally, increases in the associated price index above the swap fixed price creates valuation gains.
Transportation expenses declined primarily due to the divestiture of our Piceance properties in early 2022.
Marketing expenses decreased approximately$3 million for the nine months endedSeptember 30, 2022 when compared to the nine months endedSeptember 30, 2021 due to the sale of our Piceance Colorado operations in the fourth quarter 2021, which included third-party marketing activities. Piceance has historically accounted for nearly all of our marketing revenues. 47
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General and administrative expenses increased$19 million , or 37%, to approximately$70 million for the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 . The majority of the increase was from the acquisition of CJWS in October of 2021; therefore, the comparable period of last year had no such expenses. For the nine months endedSeptember 30, 2022 andSeptember 30, 2021 , general and administrative expenses included non-cash stock compensation costs of approximately$12 million and$10 million , respectively. We incurred approximately$0.7 million related to the CJWS acquisition which have been categorized as non-recurring for the nine months endedSeptember 30, 2021 . There was approximately$0.2 million of non-recurring expenses in the same period of 2022. Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, increased$17 million , or 42%, to$57 million for the nine months endedSeptember 30, 2022 compared to$40 million for the nine months endedSeptember 30, 2021 . A substantial majority of the year-over-year increase was due to the CJWS acquisition, as well as employee cost inflation and higher professional services expenses. DD&A increased$12 million , or 11%, to approximately$117 million for the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 . The CJWS acquisition increased depreciation by$9 million with the balance of the increase from slightly higher depletion rates in the D&P segment.
Taxes, Other Than Income Taxes
Nine Months Ended September 30, 2022 2021 $ Change % Change (per boe) Severance taxes$ 1.42 $ 0.92 $ 0.50 54 % Ad valorem and property taxes 1.49 1.91 (0.42) (22) % Greenhouse gas allowances 0.60 1.82 (1.22) (67) % Total taxes other than income taxes$ 3.51 $ 4.65 $
(1.14) (25) %
Taxes, other than income taxes decreased 25% to$3.51 per boe for the nine months endedSeptember 30, 2022 compared to$4.65 per boe for the nine months endedSeptember 30, 2021 . Severance taxes increased due to higher production and prices inUtah , while property taxes were lower due to the divestitures of Piceance and Placerita. GHG expense decreased due to lower emissions from the divestiture of Placerita and its cogeneration facility and allowances we acquired at comparatively lower prices.
Other Operating Expenses (Income)
For the nine months endedSeptember 30, 2022 , other operating expenses were$5 million and mainly consisted of over$2 million in royalty audit charges incurred prior to our emergence and restructuring in 2017 and approximately$2 million loss on the divestiture of the Piceance properties. For the nine months endedSeptember 30, 2021 , other operating expenses were$5 million and mainly consisted of approximately$3 million of unamortized debt issuance costs related to the termination of the 2017 RBL Facility, approximately$3 million of supplemental property tax assessments, royalty audit charges and tank rental costs and$1 million of various other costs such as abandonment costs and legal fees, partially offset by$2 million of income from employee retention credits.
Interest Expense
Interest expense decreased 5% in the nine months ended
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Income Taxes
Our effective tax rate was 5% for the nine months ended
Non-GAAP Financial Measures
Adjusted EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and Discretionary Free Cash Flow
Adjusted Net Income (Loss) is not a measure of net income (loss), and Discretionary Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted Net Income (Loss) and Discretionary Free Cash Flow are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA 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. Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. 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. We also use Adjusted EBITDA in planning our capital allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility. Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual and infrequent items, and the income tax expense or benefit of these adjustments using our effective tax rate. We define Discretionary Free Cash Flow as cash flow from operations less regular fixed dividends and the capital needed to hold production flat. We expect to allocate 60% of Discretionary Free Cash Flow predominantly in the form of cash variable dividends, as well as opportunistic debt repurchases. The remaining 40% will be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Our management believes Discretionary Free Cash Flow provides useful information in assessing our financial condition, and is the primary metric to determine the quarterly variable dividend. Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and infrequent costs. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period. We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature.
While Adjusted EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and Discretionary Free Cash Flow are non-GAAP measures, the amounts included in the calculation of Adjusted
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EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and Discretionary Free Cash Flow were computed in accordance with GAAP. These measures are 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. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and Discretionary Free Cash Flow may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and Discretionary Free Cash Flow should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. The following tables present reconciliations of the non-GAAP financial measures Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided or used by operating activities, as applicable, for each of the periods indicated. Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2022 2022 2021 2022 2021 (in thousands) Adjusted EBITDA reconciliation to net income (loss): Net income (loss)$ 191,660 $ 43,354 $ 9,836 $ 178,204 $ (24,367) Add (Subtract): Interest expense 7,867 7,729 7,810 23,271 24,513 Income tax expense (benefit) 10,884 2,145 (758) 9,678 (1,206) Depreciation, depletion and 39,506 38,055 35,902 117,338 105,592
amortization
(Gains) losses on derivatives (143,221) 51,319 15,885 40,902 85,672 Net cash paid for scheduled (14,739) (37,628) (17,622) (84,519) (54,204) derivative settlements Other operating expenses 623 353 3,986 4,745 4,827 Stock compensation expense 4,401 4,420 3,580 12,623 10,219 Non-recurring costs - - 705 198 705 Adjusted EBITDA$ 96,981 $ 109,747 $ 59,324 $ 302,440 $ 151,751 Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2022 2022 2021 2022 2021 (in thousands) Adjusted EBITDA reconciliation to net cash provided by operating activities: Net cash provided by operating$ 95,762 $ 111,242 $ 22,399 $ 255,534 $ 82,258 activities Add (Subtract): Cash interest payments 14,493 449 14,189 29,481 29,114 Cash income tax payments 321 2,484 294 2,805 294 Non-recurring costs - - 705 198 705 Other changes in operating assets (13,595) (4,428) 21,737 14,422 39,380 and liabilities Adjusted EBITDA$ 96,981 $ 109,747 $ 59,324 $ 302,440 $ 151,751 50
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The following table presents a reconciliation of the non-GAAP financial measure Discretionary Free Cash Flow to the GAAP financial measure of operating cash flow for each of the periods indicated. Three Months Ended Nine Months Ended September 30, 2022 June 30, 2022 September 30, 2022 (in thousands) Discretionary Free Cash Flow: Operating cash flow(1) $ 95,762$ 111,242 $ 255,534 Subtract: Maintenance capital(2)(3) (38,312) (32,134) (96,883) Fixed dividends(4) (4,726) (4,726) (14,688) Discretionary Free Cash Flow $ 52,724$ 74,382 $ 143,963 __________ (1) On a consolidated basis. (2) D&P business only. (3) Maintenance capital is the capital required to keep annual production flat, calculated as the capital expenditures for the D&P business during the period presented.
(4) Represents fixed dividends declared which are included in the "Dividends declared on common stock" line in the the consolidated statement of stockholders' equity.
Discretionary Free Cash Flow was$53 million in the third quarter of 2022 compared to$74 million in the second quarter of 2022. The key drivers of the lower Discretionary Free Cash Flow in the third quarter included the$14 million semi-annual interest payment and a$6 million increase in maintenance capital. The quarterly variable dividend is 60% of Discretionary Free Cash Flow based on our shareholder return model which began in 2022. 51
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The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss) to the GAAP financial measure of net income (loss). Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2022 2022 2021 2022 2021 (in thousands) Adjusted Net Income (Loss) reconciliation to net income (loss): Net income (loss)$ 191,660 $ 43,354 $ 9,836 $ 178,204 $ (24,367) Add (Subtract): (Gains) losses on derivatives (143,221) 51,319 15,885 40,902 85,672 Net cash paid for scheduled (14,739) (37,628) (17,622) (84,519) (54,204) derivative settlements Other operating expenses 623 353 3,986 4,745 4,827 Non-recurring costs - - 705 198 705 Total additions, net (157,337) 14,044 2,954 (38,674) 37,000 Income tax benefit (expense) of adjustments and discrete income tax 11,192 (4,262) (1,254) 1,992 (1,765) items Adjusted Net Income$ 45,515 $ 53,136 $ 11,536 $ 141,522 $ 10,868
Basic EPS on Adjusted Net Income $ 0.58
$ 0.14 $ 1.78 $ 0.14
Diluted EPS on Adjusted Net Income $ 0.55
$ 0.14 $ 1.70 $ 0.13
Weighted average shares of common 78,044 79,596 80,242 79,304 80,277 stock outstanding - basic Weighted average shares of common 82,045 83,015 82,898 83,472 82,715 stock outstanding - diluted 52
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The following table presents a reconciliation of the non-GAAP financial measure Adjusted General and Administrative Expenses to the GAAP financial measure of general and administrative expenses for each of the periods indicated. Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2022 2022 2021 2022 2021 (in thousands) Adjusted General and Administrative Expense reconciliation to general and administrative expenses: General and administrative expenses$ 23,388 $ 23,183 $ 17,614 $ 69,513 $ 50,749
Subtract:
Non-cash stock compensation expense (4,281) (4,263) (3,467) (12,250) (9,899) (G&A portion) Non-recurring costs - - (705) (198) (705)
Adjusted general and administrative
$ 13,442 $ 57,065 $ 40,145
expenses
Development and production segment,
$ 13,442 $ 47,386 $ 40,145 and corporate Development and production segment, $ 6.66$ 6.55 $ 5.34 $ 6.62 $ 5.40 and corporate per $/boe Well servicing and abandonment segment$ 3,324 $ 3,285 $ -$ 9,679 $ - 53
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Liquidity and Capital Resources
Currently, we expect to fund the remainder of our 2022 capital expenditures with cash flows from our operations. As ofSeptember 30, 2022 , we had liquidity of$256 million , consisting of$48 million cash on hand,$193 million available for borrowings under our 2021 RBL Facility and$15 million available for borrowings under our 2022 ABL Facility (as defined below). We also have$400 million in aggregate principal amount 7% senior unsecured notes dueFebruary 2026 (the "2026 Notes") outstanding as further discussed below. In accordance with our shareholder return model, which went into effectJanuary 1, 2022 , we increased cash returns to our shareholders, further demonstrating our commitment to be a leading returner of capital to our shareholders. The model is based on our Discretionary Free Cash Flow, which is defined as cash flow from operations less regular fixed dividends and the capital needed to hold oil and gas production flat. See "Management's Discussion and Analysis-Non-GAAP Financial Measures" for reconciliation of Discretionary Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. Under this model, the company intends to allocate Discretionary Free Cash Flow on a quarterly basis as follows: (a) 60% predominantly in the form of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; (b) 40% in the form of discretionary capital, to be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. We currently believe that our liquidity, capital resources and cash on hand will be sufficient to conduct our business and operations for at least the next 12 months. In the longer term, if oil prices were to significantly decline and remain weak, we may not be able to continue to generate the same level of Discretionary Free Cash Flow we are currently generating and our liquidity and capital resources may not be sufficient to conduct our business and operations until commodity prices recover. Please see Part II, Item 1A "Risk Factors" for a discussion of known material risks, many of which are beyond our control, that could adversely impact our business, liquidity, financial condition, and results of operations. 2021 RBL Facility OnAugust 26, 2021 ,Berry Corp , as a guarantor, together withBerry 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 onAugust 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. InDecember 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. InMay 2022 ,Berry Corp. , as a guarantor, andBerry 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 byBerry LLC in C&J and/or C&J Management, 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, untilOctober 1, 2022 , require hedges for any full calendar month from and afterJanuary 1, 2025 , as further described in the Second Amendment. InMay 2022 , we also completed our semi-annual borrowing base redetermination and entered into the Third Amendment to the 54
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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 theLondon 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%). If the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the 2021 RBL Facility exceeds the borrowing base at any time as a result of a redetermination of the borrowing base, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, deliver reserve engineering reports and mortgages covering additional oil and gas properties sufficient in certain lenders' opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the next six-month period. Upon certain adjustments to the borrowing base other than a result of a redetermination, we are required to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the 2021 RBL Facility exceeds the borrowing base. In addition, the 2021 RBL Facility provides that if there are any outstanding borrowings and the consolidated cash balance exceeds$20 million at the end of each calendar week, such excess amounts shall be used to prepay borrowings under the credit agreement. Otherwise, any unpaid principal will be due at maturity. The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary base rate plus an applicable margin ranging from 2.0% to 3.0% per annum, and (ii) a customary benchmark rate plus an applicable margin ranging from 3.0% to 4.0% per annum, and in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.5% on the average daily unused amount of the borrowing availability under the 2021 RBL Facility. We have the right to prepay any borrowings under the 2021 RBL Facility with prior notice at any time without a prepayment penalty. The 2021 RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a leverage ratio of not more than 3.0 to 1.0 and (ii) a current ratio of not less than 1.0 to 1.0. As ofSeptember 30, 2022 , our leverage ratio and current ratio were 1.2:1.0 and 2.3:1.0, respectively. In addition, the 2021 RBL Facility currently provides that, to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants under the 2021 RBL Facility as ofSeptember 30, 2022 . The 2021 RBL Facility contains usual and customary events of default and remedies for credit facilities of a similar nature. The 2021 RBL Facility also places restrictions on the borrower and its restricted subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of the borrower's senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. From and afterAugust 26, 2022 , the 2021 RBL Facility permits us to repurchase certain indebtedness so long as both before and after giving pro forma effect to such repurchase, no default or event of default exists, availability is equal to or greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0. The 2021 RBL Facility also permits us to make restricted payments so long as both before and after giving pro forma effect to such distribution, no default or event of default exists, availability exceeds 75% of the borrowing base, and our pro forma leverage ratio is less than or equal to 1.5 to 1.0. In addition, we can make other restricted payments in an aggregate amount not to exceed 100% of Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such distribution so long as, in addition to other conditions and limitations as described in the 2021 RBL Facility, both before and after giving pro forma effect to such distribution, no default or event of default exists, availability is greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0.
55 -------------------------------------------------------------------------------- Table of ContentsBerry Corp. , with certain exceptions, is required to guarantee our obligations and obligations of the other guarantors under the 2021 RBL Facility and under certain hedging transactions and banking services arrangements (the "Guaranteed Obligations"). The lenders under the 2021 RBL Facility hold a mortgage on at least 90% of the present value of our proven oil and gas reserves. The obligations ofBerry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions.
As of
2022 ABL Facility
OnAugust 9, 2022 , C&J and C&J Management, which are the two entities that constitute the well servicing and abandonment segment referred to as CJWS, as borrowers, entered into a credit agreement withTri Counties Bank , as lender, that provides for a revolving loan facility, subject to satisfaction of customary conditions precedent to borrowing, of up to the lesser of (x)$15 million and (y) the borrowing base ("the "2022 ABL Facility"). The "borrowing base" is an amount equal to 80% percent of the balance due on eligible accounts receivable, subject to reserves thatTri Counties Bank may implement in its reasonable discretion. Interest on the outstanding principal amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of The Wall Street Journal Prime Rate. The "Wall Street Journal Prime Rate" is the variable rate of interest, on a per annum basis, which is announced and/or published in the "Money Rates" section ofThe Wall Street Journal from time to time as its "Prime Rate". The rate will be redetermined whenever The Wall Street Journal Prime Rate changes. Interest is due quarterly, in arrears, starting onSeptember 30, 2022 and will continue to be due and payable in arrears on the last day of each calendar quarter thereafter. OnJune 5, 2025 the entire unpaid principal balance of the revolving loans under the 2022 ABL Facility, and all unpaid interest thereon, will be due and payable. The 2022 ABL Facility provides a letter of credit sub-facility for the issuance of letters of credit in an aggregate amount not to exceed$7.5 million . The 2022 ABL Facility requires CJWS to comply with the following financial covenants (i) maintain on a consolidated basis a ratio of total liabilities to tangible net worth of no greater than 1.5 to 1.0 at any time; (ii) reduce the amount of revolving advances outstanding under the 2022 ABL Facility to not more than 90% of the lesser of (a) the maximum revolving advance amount, or (b) the borrowing base, as ofTri Counties Bank's close of business on the last day of each fiscal quarter; and (iii) maintain net income before taxes of not less than$1.00 as of each fiscal year end. The 2022 ABL Facility contains usual and customary events of default and remedies for credit facilities of a similar nature. The 2022 ABL Facility also places restrictions on CJWS with respect to additional indebtedness, liens, dividends and other distributions, investments, acquisitions, mergers, asset dispositions and other matters. CJWS's obligations under the 2022 ABL Facility are not guaranteed byBerry Corp. orBerry LLC andBerry Corp. andBerry LLC do not and are not required to provide any credit support for such obligations. We were in compliance with all financial covenants under the 2022 ABL Facility as ofSeptember 30, 2022 .
As of
Hedging We have protected a significant portion of our anticipated cash flows in 2022 through 2024, using our commodity hedging program, including swaps, puts, calls and collars. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge natural gas purchases to protect against price increases. In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. Our generally low-decline production base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our current hedging positions. For information regarding risks related to our hedging program, see "Item 1A. Risk Factors-Risks Related to Our Operations and Industry" in our Annual Report. 56
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As ofOctober 31, 2022 , we had the following hedges for our crude oil production and gas purchases. Q4 2022 FY 2023 FY 2024 FY 2025 Brent Swaps Hedged volume (bbls) 1,516,750 5,165,028 3,367,610 - Weighted-average price ($/bbl)$ 78.24 $ 76.67 $ 76.07 $ - Put Spreads Hedged volume (bbls) 368,000 2,190,000 1,281,000 - Weighted-average price ($/bbl)$50.00 /$40.00 $50.00 /$40.00 $50.00 /$40.00 $ - Producer Collars Hedged volume (bbls) - 1,460,000 1,098,000 365,000 Weighted-average price ($/bbl) $ -$40.00 /$106.00 $40.00 /$105.00
Consumer Collars Hedged volume (mmbtu) 3,680,000 5,430,000 - - Weighted-average price ($/mmbtu)$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
The following table summarizes the historical results of our hedging activities. Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, September 30, 2022 2022 2021 2022 2021 Crude Oil (per bbl): Realized sales price, before the$ 89.54 $ 105.70
$ 76.41 $ 83.78
$ 5.79 $ 7.24 $ 5.32
of derivative settlements
Effects of derivative settlements
$ 3.49 $ 5.71 $ 2.98 Cash Dividends For the nine months endedSeptember 30, 2022 , our Board of Directors declared quarterly fixed cash dividends totaling$0.18 per share, as well as variable cash dividends of$0.69 per share which were based on the results of the first two quarters of 2022, for a total of$0.87 per share. InOctober 2022 , the Board of Directors approved the fourth quarter$0.06 per share fixed cash dividend, as well as a variable dividend of$0.41 based on the third quarter results. The Company anticipates that it will continue to pay quarterly cash dividend in the future. However, the payment and amount of future dividends remain within the discretion of the Board and will depend upon the Company's future earnings, financial condition, capital requirements, and other factors. 57
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The following table represents the regular fixed cash dividends on our common stock and variable dividends approved by our Board of Directors.
First Quarter Second Quarter Third Quarter Fourth Quarter Year-to-Date Fixed Dividends $ 0.06 $ 0.06 $ 0.06 $ 0.06$ 0.24 Variable Dividends(1) 0.13 0.56 0.41 - 1.10 Total $ 0.19 $ 0.62 $ 0.47 $ 0.06$ 1.34 __________
(1) Variable Dividends are declared the quarter following the period of results (the period used to determine the variable divided based on the shareholder return model). The table notes total dividends earned in each quarter.
Stock Repurchase Program
We repurchased 2,000,000 shares during the three months endedSeptember 30, 2022 for approximately$19 million . For the nine months endedSeptember 30, 2022 , we repurchased 4,000,000 shares for approximately$42 million . As ofSeptember 30, 2022 , the Company had repurchased a total of 9,528,704 shares under the stock repurchase program for approximately$94 million in aggregate, which is 12% of outstanding shares. 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. InApril 2022 , our Board of Directors approved an increase of$102 million to the Company's stock repurchase authorization bringing the Company's remaining share repurchase authority to$150 million . As ofSeptember 30, 2022 , the Company's remaining total share repurchase authority is$108 million , after the repurchases made in the second and third quarters of 2022. The Board's authorization permits the Company to make purchases of its common stock from time to time in the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the aggregate amount authorized by the Board. The Board's authorization has no expiration date. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate the company to purchase shares during any period or at all. Any shares repurchased are reflected as treasury stock and any shares acquired will be available for general corporate purposes.
Debt Repurchase Program
InFebruary 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 obligateBerry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any notes under this program. 58
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