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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2022
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from_______________ to _______________
Commission file number 001-38606
BERRY CORPORATION (bry)
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation or organization)
81-5410470
(I.R.S. Employer Identification Number)
16000 Dallas Parkway, Suite 500
Dallas, Texas 75248
(661616-3900
(Address of principal executive offices, including zip code
Registrant’s telephone number, including area code):
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $0.001 per share
Trading Symbol
BRY
Name of each exchange on which registered
Nasdaq Global Select Market
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes     No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes    No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer 
 
Accelerated filer
 
Non-accelerated filer 
 
Smaller reporting company
         Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes     No 
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐



The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $501.6 million.
Shares of common stock outstanding as of January 31, 2023:                         75,767,503

DOCUMENTS INCORPORATED BY REFERENCE
The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 23, 2023) will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2022 and is incorporated by reference in Part III to the extent described herein.



Table of Contents
i




The financial information and certain other information presented in this report have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this report. In addition, certain percentages presented in this report reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding.

ii


Table of Contents
Index to Financial Statements and Supplementary Data
Part I
Items 1 and 2. Business and Properties
“Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation, which is the sole member of each of its three Delaware limited liability company subsidiaries: (1) Berry Petroleum Company, LLC (“Berry LLC”), (2) CJ Berry Well Services Management, LLC (“C&J Management”) and (3) C&J Well Services, LLC (“C&J”). As the context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its consolidated subsidiary, Berry LLC, and as of October 1, 2021 this also includes C&J Management and C&J.
Our Company
We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah (oil and gas), with well servicing and abandonment capabilities in California. Since October 1, 2021, we have operated in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment (“CJWS”).
The assets in our E&P business, in the aggregate, are characterized by high oil content (our California assets are 100% oil) and are predominantly located in rural areas with low population. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. The California oil market has primarily Brent-influenced pricing which has typically realized premium pricing to WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin, which has more than 150 years of production history and substantial oil remaining in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics and low geological risk opportunities are well understood. We also have upstream assets in the oil-rich reservoirs in the Uinta basin of Utah.
On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J Well Services (“CJWS”) and constitutes our well servicing and abandonment segment. CJWS provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics. CJWS’ services include rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic growth opportunity for Berry based on the significant market of idle wells.
Since our Initial Public Offering (IPO) in July 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 returns to our shareholders. Under this well-defined shareholder return model, we declared variable dividends of $1.54 per share in aggregate based on the $200 million of Adjusted Free Cash Flow (defined and discussed below) that we generated in 2022. We also declared fixed dividends of $0.24 during 2022. Inclusive of the fixed and variable dividends related to the fourth quarter of 2022, since our IPO, we will have returned $328 million to our shareholders, which represents 298% of our IPO proceeds, consisting of $224 million in fixed and variable dividends and $104 million to repurchase 10.5 million shares, which represents 14% of our outstanding shares as of December 31, 2022.
Our shareholder return model went into effect January 1, 2022. Like our business model, this shareholder return model is simple and demonstrates our commitment to optimize capital allocation and returns to our shareholders. The model is based on our Adjusted Free Cash Flow (formerly called Discretionary Free Cash Flow), which is defined as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital, which represents the capital expenditures needed to optimize production volumes for a given year, is defined as
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capital expenditures, excluding, when applicable, (i) E&P capital expenditures that are related to strategic business expansion, such as acquisitions and divestitures of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes, (ii) capital expenditures in our well servicing and abandonment segment, (iii) corporate expenditures that are related to ancillary sustainability initiatives and/or (iv) other expenditures that are discretionary and unrelated to maintenance of our core business. The initial allocation of Adjusted Free Cash Flow in 2022 was contemplated as: (a) 60% predominantly in the form of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; and (b) 40% which could 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. Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchase or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure. Adjusted Free Cash Flow is a non-GAAP financial measure. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for a reconciliation of Adjusted Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.
Our Adjusted Free Cash Flow in 2022 was $200 million, of which we will have returned $189 million to shareholders in the form of dividends and share repurchases, specifically, $119 million for the variable cash dividends, (ii) $19 million for fixed cash dividends and (iii) $51 million for share repurchases.
In early February 2023, we updated our shareholder return model, including the plan to double our quarterly fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to continue maximizing shareholder value through overall returns. Starting with the first quarter of 2023, the allocation of Adjusted Free Cash will be (a) 80% primarily in the form of opportunistic debt or share repurchases; and (b) 20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors.
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 free cash flow, which funds our operations, optimizes capital efficiency and maximizes shareholder returns. We also strive to maintain a low leverage profile and explore attractive organic and strategic growth through commodity price cycles. 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 shareholders, 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. We are committed to being part of the energy transition solution by continuing to provide safe and affordable energy to our communities.
The Berry Advantage
The foundation of our business model is our base production, which is the production that comes from our existing, producing wells. Our goal is to protect our base production and minimize its decline with the objective of maintaining relatively stable production levels year over year. In terms of that goal, our base production on average, typically accounts for greater than 90% of our total annual production, and the remaining 10% comes from a mixture of drilling new wells, sidetrack wells, and the workover of existing wells. In 2022, our base production accounted for 94% of our total production. We have a manageable annual corporate decline rate in the low teens, with significant inventory of new drill and workover opportunities and predictable costs, which provides visibility to our
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potential cash flow options. Our ability to pivot our capital allocation between new drills and sidetrack and workovers in response to regulatory delays or other factors provides further stability in an uncertain market and regulatory environment. These advantages, coupled with an ability to efficiently hedge material quantities of future expected production, provides visibility to our cash flows compared to the typical resource play and can generate significant cash flow through typical commodity price cycles.
We believe the following competitive advantages will allow us to successfully execute our business strategy and meet our objectives to generate free cash flow to fund our operations, optimize capital efficiency and maximize shareholder returns. We also strive to maintain a low leverage profile and explore attractive organic and strategic growth through commodity price cycles:
Stable, long-lived, oil-weighted conventional asset base with low and predictable production decline rates. Almost all of our interests are in properties that have produced oil for decades. As a result, most of the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present lower risk than unconventional resource plays. Our properties, especially those in California, are characterized by long-lived reserves with low production decline rates, a stable development cost structure and low-geologic risk developmental drilling opportunities with predictable production profiles. Our current corporate annual decline rate is in the low teens, which is manageable and provides greater visibility into our cash flows compared to unconventional resource plays. In California, our base production from existing wells requires little to no additional capital to continue to produce, and it typically provides at least 90% of the production needed to maintain relatively stable levels year over year. The remaining 10% comes from a mixture of drilling new wells, side tracks, and the workover of existing wells. The nature of our assets also provides us with significant capital flexibility (discussed further below) and an ability to efficiently hedge material quantities of future expected production, further enhancing visibility to our cash flow.
Extensive inventory of low geological risk identified drilling opportunities with attractive full-cycle economics, high operational control and a stable development and production cost environment provides capital flexibility. Historically, we have been able to generate attractive rates of return and positive free cash flow through typical commodity price cycles. Subject to our ability to obtain the necessary permits and approvals to drill new wells and sidetracks and workover existing wells, we believe we will be able to maintain current production levels and fund organic and strategic growth, among other things, while returning capital to shareholders. For example, our proved undeveloped (“PUD”) reserves in California are projected to average single-well rates of return of approximately 100% based on the assumptions prepared by DeGolyer and MacNaughton in our SEC reserves report as of December 31, 2022. We currently operate approximately 97% of our producing wells and we expect this level of control to continue for our identified gross drilling locations. In addition, a substantial majority of our acreage is currently held by production and fee interest, including 91% of our acreage in California. Our high degree of control over our properties gives us flexibility in executing our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production. Also, unlike many of our peers who operate primarily in unconventional plays, our assets generally do not necessitate supply-constrained and highly specialized equipment, which provides us some relative insulation from service cost inflation pressures. Our high degree of operational control and relatively stable and predictable cost environment provides us visibility and understanding of our expected cash flow.
Brent-influenced crude oil pricing advantage. California oil prices are Brent-influenced as California refiners import approximately 70% of the state’s demand from OPEC+ countries and other waterborne sources. Without the higher costs and potential environmental impact associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing should continue to allow us to realize positive cash margins in California over the typical commodity price cycles.
Simple capital structure and conservative balance sheet leverage with ample liquidity and minimal contractual obligations. Since our IPO, our capital structure has consisted of common stock and $400
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million of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”). As of December 31, 2022, we had $252 million of liquidity, consisting of $46 million of cash, $193 million available for borrowings under our 2021 RBL Facility (as defined herein), and $13 million available for borrowings under the CJWS 2022 ABL Facility (as defined herein). As of December 31, 2022, our Leverage Ratio (as defined in our 2021 RBL Facility) was 1.2 to 1.0. In addition, we have minimal long-term service and purchase commitments. We have fixed-volume delivery commitments for which we will purchase the gas needed for operations at market rates. This liquidity and flexibility permit us to capitalize on opportunities that may arise to strategically grow and increase stockholder value.
Experienced, principled and disciplined management team. Our management team has significant experience operating and managing oil and gas businesses across numerous domestic and international basins, as well as reservoir and recovery types. We use our technical, operational and strategic management experience to optimize the value of our assets and the Company. We are committed to operating within positive free cash flow and maintaining a low leverage profile, while exploring attractive organic and strategic growth opportunities through commodity price cycles, and working to maintain our production levels year over year and improve the value of our reserves. In doing so, we take a disciplined approach to development and operating cost management, field development efficiencies and the application of proven technologies and processes to our properties in order to generate a sustained life-cycle cost advantage.
Our Business Strategy
The principal elements of our business strategy include the following:
Operate within the positive free cash flow generated by our operations and maintain balance sheet strength and flexibility through commodity price cycles. 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 free cash flow to fund our operations, optimize capital efficiency, and maximize shareholder returns. We also strive to maintain a low leverage profile and maintain a long-term, through-cycle Leverage Ratio (as defined in our 2021 RBL Facility) between 1.0x and 2.0x, or lower.
Return capital to our shareholders. Our objective is to take advantage of our base production and the visibility into our cash flow to maintain disciplined value creation and a returns-focused approach to capital allocation in order to generate excess free cash flow. Since our 2018 IPO through December 31, 2022, we will have returned approximately $328 million to our shareholders through dividends and share repurchases, representing 298% of our IPO proceeds. From our IPO through December 31, 2022, we repurchased approximately 14% of our outstanding shares. We currently have $200 million authorized and available for future share repurchases. Additionally, our Board of Directors authorized up to $75 million for the opportunistic repurchase of our 2026 Notes, although we have not yet repurchased any notes under this program since its adoption in February 2020. For a discussion of our dividend policy, as well as our stock repurchase program, please see “Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
In January 2022, we introduced our shareholder return model, which is designed to increase cash returns to our shareholders, further demonstrating our commitment to be a leading returner of capital to its shareholders. The model is based on our Adjusted Free Cash Flow (formerly called Discretionary Free Cash Flow), which is defined as cash flow from operations less regular fixed dividends and maintenance capital. Under this model, in 2022 we allocated Adjusted Free Cash Flow on a quarterly basis as follows:
60% predominantly in the form of cash variable dividends to be paid quarterly, as well as opportunistic debt repurchases; and

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40% 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

In early February 2023, we updated our shareholder return model, including the plan to double our quarterly fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to continue maximizing shareholder value through overall returns. Starting with the first quarter of 2023, the allocation of Adjusted Free Cash will be:
80% primarily in the form of opportunistic debt and share repurchases; and
20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors.
Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchase or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure. Adjusted Free Cash Flow is a non-GAAP financial measure. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for a reconciliation of Adjusted Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.
Maintain production and reserves in a capital efficient manner and generate Adjusted Free Cash Flow to return to our shareholders through our shareholder return model . We intend to continue to allocate capital in a disciplined manner to projects that will produce predictable and attractive rates of return. We currently plan to direct capital to our oil-rich and low-geologic risk development opportunities, primarily in California, while focusing on leveraging capital efficiencies across our asset base with the primary objective of internally funding our capital budget and development plan. As a result of ongoing regulatory uncertainty impacting the availability of new drill permits in California, our current capital program for 2023 focuses on new wells drilled or to be drilled during the year for which we already have permits or have existing California Environmental Quality Act (“CEQA”) analysis completed, and otherwise focuses on workovers and other activities related to existing wellbores. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically add to our positions in existing or nearby basins.
Proactively and collaboratively engage in matters related to regulation, the environment and community relations. We seek to work with regulators and legislators throughout the rule-making process in attempt to minimize the adverse impacts that new legislation and regulations might have on our ability to maximize our resources. We believe that running our operations in a manner that protects the safety and health of the communities we serve and the greater environment is the right way to run our business. It also helps us build and maintain credibility with the agencies that regulate our operations, as well as support positive relationships with the communities in which we operate. With ultimate oversight by our Board of Directors, health, safety and environmental (“HSE”) considerations are an integral part of our day-to-day operations and are incorporated into the strategic decision-making process across our business.
Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we continue to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will continue to advance and use innovative oil recovery and other recovery techniques to unlock additional value and will allocate capital towards these next generation technologies where applicable. In addition, we intend to take advantage of underdevelopment in basins where we operate by expanding our geologic investigation of reservoirs on our acreage and adjacent
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acreage below existing producing reservoirs. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs. We strive to optimize our production and grow our reserves by leveraging the expertise of our people to find or create new opportunities within our robust assets.
Enhance future cash flow stability and visibility through an active and continuous hedging program. Our hedging strategy is designed to insulate our capital program from price fluctuations by securing price realizations and cash flows for production. We use commodity pricing outlooks and our understanding of market fundamentals to better protect our cash flows - we hedge crude oil and gas production to protect against oil and gas price decreases and we hedge gas purchases to protect our operating expenses against price increases. We also seek to protect our operating expenses through fixed-price gas purchase agreements and pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that help reduce our exposure to fuel gas purchase price fluctuations. In addition, we hedge to meet the hedging requirements of the 2021 RBL Facility. We protected a significant portion of our cash flows in 2022, and have sought to protect a significant portion of our anticipated cash flows in 2023, as well as a portion in 2024 through 2025, using our commodity hedging program. We review our hedging program continuously as market conditions change and make our hedging decisions using a wide range of market data and analysis.

Continuously optimize costs. Management is focused on cost reduction initiatives and optimizing our cost structure across the company. We believe we will be able to identify and achieve cost reductions and optimize our processes and cost structure while maintaining our HSE standards.

Continue to be compliant with strong HSE performance. As part of our commitments to being a good corporate citizen and creating long-term stockholder value, we strive to conduct our operations in an ethical, safe and responsible manner that safeguards people and the environment and complies with existing laws and regulations and to take care of our people and the communities in which we live and operate. We monitor our HSE performance through various measures, and we hold our employees and contractors to high standards. Meeting corporate HSE metrics, including with respect to HSE incidents, is a part of our short-term incentive program for all employees.

Continue to improve our environment through our CJWS plugging and abandonment business and other initiatives. We believe that oil and gas will remain an important part of the energy landscape going forward and we are committed to being good corporate citizens, which includes minimizing our environmental impact. Through CJWS, we have the capabilities to support the State's orphaned wells and fugitive emissions initiatives related to its approximately 35,000 idle wells, of which approximately 5,000 are believed to be orphaned idle wells according to third party sources. CJWS is an active contributor to the reduction of state-wide fugitive emissions, which are primarily methane, the most damaging of the greenhouse gases, by plugging and abandoning orphan and idle wells. Additionally, we are continuing to advance other environmental initiatives, including solar and water recycling projects and we are evaluating our acreage for carbon capture, use and storage opportunities.
Our Capital Program
For the years ended December 31, 2022 and 2021 our total capital expenditures were approximately $153 million and $133 million, respectively, including capitalized overhead and interest and excluding acquisitions and asset retirement spending. We increased our 2022 capital program compared to 2021, in response to the improved oil price environment and the improving global and national economic environment. E&P and corporate expenditures were $145 million in 2022 (excluding well servicing and abandonment capital of $8 million) compared to $132 million in 2021. Approximately 61% and 39% of these capital expenditures for the year ended December 31, 2022 was directed to California and Utah operations, respectively. The Company allocated more capital to the Utah assets in 2022, compared to 2021, in part due to the opportunities in the newly acquired Antelope Creek properties. Additionally, as a result of the significant challenges in receiving new drill permits in California, the
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Company drilled fewer new wells and increased the sidetrack, workover and recompletion activity in California compared to the prior year. 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.
Year-over-year our overall production was flat, excluding the effect of our acquisitions and divestitures in 2022 and 2021. We drilled 85 wells in 2022, of which 72 were in California and consisted of 51 producing wells 13 injector and other wells and 8 delineation wells. We also drilled 13 wells in Utah.
Our 2023 capital expenditure budget for E&P operations and corporate activities is between $95 to $105 million, which we expect will result in a slight decline in production year over year but that production levels will be relatively flat to those experienced in the second half of 2022. This capital excludes approximately $8 million for CJWS. We currently anticipate oil production will be approximately 92% of total production volume in 2023, consistent with 2022. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2023 capital development programs from cash flow from operations. Our current capital program for 2023 focuses on new wells drilled during the year for which we already have permits or have existing CEQA analysis completed, and otherwise focuses on workovers, side tracks and other activities related to existing wellbores. As a result of ongoing regulatory uncertainty in California impacting the permitting process in Kern County where all of our California assets are located, the capital program has been prepared based on the assumption that we will not receive additional new drill permits in California 2023, but that we will continue to timely receive the other permits and approvals needed for planned activities. However, we are pursuing alternative avenues to obtain additional permits for new wells that, if received could enable us to expand the 2023 drilling program contemplated under our capital budget. Please see “—Regulatory Matters” for additional discussion of the laws and regulations that impact our ability to drill and develop our assets, including those impacting regulatory approval and permitting requirements.
Exclusive of the capital expenditures noted above, for the full year 2022, we spent approximately $20 million on plugging and abandonment activities, exceeding our annual obligation requirements under California idle well management plan. In 2023, we currently expect to spend approximately $21 million to $24 million for such activities and we again plan to stay ahead of our annual plugging and abandonment obligations in keeping with our commitments to be a responsible operator.
For information about the potential risks related to our capital program, see “Item 1A. Risk Factors”, as well as “—Regulatory Matters”.
Our Areas of Operation - E&P
Our predominant E&P operating area is in California, and we also have operations in Utah. In January 2022 we divested our Colorado operating area.
California
California oil fields, including those in Kern County and the San Joaquin Basin, where our fields are located, are some of most resource-rich in the world. According to the U.S. Energy Information Administration, the San Joaquin basin in Kern County, California contained three of the 20 largest oil fields in the United States based on proved reserves. We have operations in two of those three fields —Midway-Sunset and South Belridge. All of our California operations are in the San Joaquin basin and rural Kern County with low population density. We believe there are extensive existing field redevelopment opportunities in and around our areas of operation within the San Joaquin basin, which also include the McKittrick and Poso Creek fields. We also believe that our California focus and strong balance sheet will allow us to take advantage of these opportunities. Commercial petroleum development began in the San Joaquin basin in the late 1860s when asphalt deposits were mined and shallow wells were hand dug and drilled. Rapid discovery of many of the largest oil accumulations followed during the next several decades. Operations on our properties began in 1909. In the 1960s, introduction of thermal techniques resulted in substantial new additions to reserves in heavy oil fields. The San Joaquin basin contains multiple stacked benches that have
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allowed continuing discoveries of stratigraphic, structural and non-structural traps. Most oil accumulations discovered in the San Joaquin basin occur in the Eocene age through Pleistocene age sedimentary sections. Organic rich shales from the Monterey, Kreyenhagen and Tumey formations form the source rocks that generate the oil for these accumulations.
We currently hold approximately 15,000 net acres in the San Joaquin basin in Kern County, of which 91% is held by production and fee interest. Approximately 12% of our California acres are on Federal lands administered by the Bureau of Land Management (“BLM”), of which 100% is held by production. We have a 97% average working interest in our California assets, and our producing areas include:
California operations consist of:
(i) our North Midway-Sunset sandstone properties, where we use cyclic and continuous steam injection to develop these known reservoirs; and our McKittrick Field property, which is a newer steamflood development with potential for infill and extension drilling. Also located here are our North Midway-Sunset thermal diatomite properties, which require high pressure cyclic steam techniques to unlock the significant value we believe is there and maximize recoveries.

Following the November 2019 moratorium on approval of new high–pressure cyclic steam wells to address surface expressions experienced by certain operators, we continue to await approval of our revised development plans from CalGEM, which we believe are in accordance with the results of the study co-led by Lawrence Livermore National Laboratory and CalGEM. In the meantime, we have plans to drill permitted wells in these thermal diatomite properties in 2023, which do not require high-pressure cyclic steam. Please see “—Regulation of Health, Safety and Environmental Matters—Additional CalGEM Actions on Oil and Gas Activities” for more information;
(ii) our South Midway-Sunset, properties, which are long-life, low-decline, strong-margin thermal oil properties with additional development opportunities;
(iii) our South Belridge Field Hill property, which is characterized by two known reservoirs with low geological risk containing a significant number of drilling prospects, including downspacing opportunities, as well as additional steamflood opportunities.

(iv) our Poso Creek property, which is an active mature shallow, heavy oil asset that we continue to develop. We develop these sandstone properties with a combination of cyclic and continuous steam injections, similar to many of our west California operations.

Our California proved reserves represented approximately 76% of our total proved reserves at December 31, 2022. California accounted for 21.3 mboe/d, or 82%, of our average daily production for the year ended December 31, 2022.
Along with these upstream operations, we have infrastructure and excess available takeaway capacity in place to support additional development in California. We produce oil from heavy crude reservoirs using steam to heat the oil so that it will flow to the wellbore for production. To help support this operation, we own and operate four natural gas-fired cogeneration plants that produce electricity and steam. These plants, in the Midway-Sunset and McKittrick fields, supply approximately 16% of our steam needs and approximately 55% of our field electricity needs to power our operations in California, on average generally at a discount to electricity market prices. To further help offset our costs, we also sell electricity produced by two of our cogeneration facilities under long-term contracts with terms ending in December 2023 and November 2026. We also own 62 conventional steam generators to help satisfy the steam required by our operations.
In addition, we own gathering, storage, treatment, water recycling and softening facilities, reducing our need to spend capital to develop nearby assets and generally allowing us to control certain operating costs. Approximately
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92% of our California oil production is sold through pipeline connections, however, we can also sell our oil using trucking during short-term pipeline market disruptions.
Uinta Basin, Utah
The Uinta basin is a mature, light-oil-prone play covering more than 15,000 square miles with significant undeveloped resources where we have high operational control and additional behind pipe potential. Our Uinta basin operations in the Brundage Canyon, Ashley Forest, Lake Canyon and Antelope Creek areas in Utah target the Green River and Wasatch formations that produce oil and natural gas at depths ranging from 4,000 feet to 7,000 feet. We have high operational control of our existing acreage, which provides significant upside for additional vertical and or horizontal development and recompletions. We currently hold approximately 101,000 net acres in the Uinta basin, of which 92% is held by production. Approximately 28% of our Utah acreage is on Federal lands administered by the BLM, of which 78% is held by production. Approximately 65% of our Utah acreage is on tribal lands, of which 98% is held by production.
Our Uinta basin proved reserves represented approximately 24% of our total proved reserves at December 31, 2022 and accounted for 4.8 mboe/d or 18% of our average daily production for the year ended December 31, 2022.
We also have extensive gas infrastructure and available takeaway capacity in place to support additional development along with existing gas transportation contracts. We have natural gas gathering systems consisting of approximately 500 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. We also own a natural gas processing plant in the Brundage Canyon area located in Duchesne County, Utah with capacity of approximately 30 mmcf/d. This facility takes delivery from gathering and compression facilities we operate. Approximately 88% of the gas gathered at these facilities is produced from wells that we operate. Current throughput at the processing plant is 10-17 mmcf/d and sufficient capacity remains for additional large-scale development drilling.
Formed during the late Cretaceous to Eocene periods, the Uinta basin is a mature, light-oil-prone play located primarily in Duchesne and Uintah Counties of Utah and covers more than 15,000 square miles. Exploration efforts immediately after the Second World War led to the first commercial oil discoveries in the Uinta basin. Oil was discovered in, and produced from, fluvial to lacustrine sandstones of the Green River formation in these early discoveries. The application of improved hydraulic stimulation techniques in the mid-2000s greatly increased production from the Uinta basin. As reported by the Utah Department of Natural Resources, total Utah oil production more than doubled from 36 mbbl/d in 2003 to 97 mbbl/d in 2021. Approximately 87% of Utah’s oil production in 2021 came from the Uinta basin in Duchesne and Uintah counties.
In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of Utah. These assets are adjacent to our existing Uinta assets.
Our Well Servicing and Abandonment Business
On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J Well Services and now constitutes our well servicing and abandonment business segment. CJWS provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics. CJWS’ services include rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic growth opportunity for Berry. CJWS is a synergistic fit with the services required by our oil and gas operations and supports our commitment to be a responsible operator and reduce our emissions, including through the proactive plugging and abandonment of wells. Additionally, CJWS is critical to advancing our strategy to work with the State of California to reduce fugitive emissions—including methane and carbon dioxide—from idle wells. According to independent sources, there are approximately 35,000 idle wells estimated to be in California, of which
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approximately 5,000 are believed to be orphaned idle wells. With CJWS’ expertise and experience in well abandonment, we have an opportunity to capture both state and federal funds to help remediate orphaned idle wells that are a burden on the State of California, in addition to safely plugging and abandoning idle wells for CJWS’ customers.
Through CJWS, we operate a fleet of 72 well servicing rigs, also commonly referred to as a workover rig, and related equipment. These services are performed to establish, maintain and improve production throughout the productive life of an oil and natural gas well and to plug and abandon a well at the end of its productive life. Our well servicing business performs various services to establish, maintain and improve production throughout the productive life of an oil and natural gas well, which include:
Maintenance work involving removal, repair and replacement of down-hole equipment and components, and returning the well to production after these operations are completed;
Well workovers which potentially include deepening, sidetracks, adding productive zones, isolating intervals, or repairing casings required by the operation into and out of the well, or removing equipment from the wellbore; and
Plugging and abandonment services when a well has reached the end of its productive life.
Regular maintenance is required throughout the life of a well to sustain optimal levels of oil and natural gas production. Regular maintenance currently comprises the largest portion of our well services work, and because ongoing maintenance spending is required to sustain production, we have historically experienced relatively stable demand for these services.
In addition to periodic maintenance, producing oil and natural gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. The demand for workover services is sensitive to oil and natural gas producers’ intermediate and long-term expectations for oil and natural gas prices. As oil and natural gas prices increase, the level of workover activity tends to increase as oil and natural gas producers seek to increase output by enhancing the efficiency of their wells.
Well servicing rigs are also used in the process of permanently closing oil and natural gas wells no longer capable of producing in economic quantities. Plugging and abandonment work can provide favorable operating margins and is less sensitive to oil and natural gas prices than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive.
Our water logistics business utilizes our fleet of 247 water logistics trucks and related assets, including specialized tank trucks, storage tanks and other related equipment. These assets provide, transport, and store a variety of fluids, as well as provide maintenance services. These services are required in most workover and remedial projects and are routinely used in daily producing well operations. We also have approximately 1,370 pieces of rental equipment on our water logistics side.
Our Assets and Production Information
For the year ended December 31, 2022, we had average net production of approximately 26.1 mboe/d, of which approximately 92% was oil and approximately 82% was in California. In California, our average production for the year ended December 31, 2022 was 21.3 mboe/d, of which 100% was oil. Our 2021 California production included our previously owned Placerita operations, which contributed an average daily production of 0.7 mboe/d for 2021. We divested the Placerita operations in late 2021. We also divested all of our properties in the Piceance basin of Colorado in January 2022, which had production of 1.2 mboe/d in 2021. In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of Utah. These assets are adjacent to our existing Uinta assets and contributed an average daily production of approximately 1.0 mboe/d for 2022.
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The table below summarizes our average net daily production for the years ended December 31, 2022 and 2021:
Average Net Daily Production(1)
for the Year Ended December 31,
20222021
(mboe/d)Oil (%)(mboe/d)Oil (%)
California(2)
21.3 100 %22.0 100 %
Utah(3)
4.7 58 %4.2 51 %
26.0 92 %26.2 88 %
Colorado(4)
0.1 — %1.2 %
Total
26.1 92 %27.4 88 %
__________
(1)    Production represents volumes sold during the period.
(2)    Includes production for Placerita properties though the end of October 2021 when they were divested. These properties had average daily production in 2021 of approximately 700 boe/d.
(3)     Includes production for Antelope Creek area, which was acquired in February 2022. These properties had average production for 2022 of approx 1.0 mboe/d.
(4)    Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.
Production Data
The following table sets forth information regarding production for the years ended December 31, 2022 and 2021.
Year Ended December 31,
20222021
Average daily production(1):
Oil (mbbl/d)24.0 24.2 
Natural gas (mmcf/d)10.2 17.1 
NGLs (mbbl/d)0.4 0.4 
Total (mboe/d)(2)
26.1 27.4 
__________
(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 year ended December 31, 2022, the average prices of Brent oil and Henry Hub natural gas were $99.04 per bbl and $6.45 per mcf, respectively.
Our Development Inventory
We have an extensive inventory of low-geologic risk, high-return development opportunities. As of December 31, 2022, we identified 9,813 proven and unproven gross drilling locations across our asset base. For a discussion of how we identify drilling locations, please see “—Our Reserves—Determination of Identified Drilling Locations.”
We operate approximately 97% of our producing wells. In addition, a substantial majority of our acreage is currently held by production and fee interest, including 91% of our acreage in California. As of December 31, 2022, the combined net acreage covered by leases expiring in the next three years represented approximately 2% of our total net acreage, of which 55% is in Utah. Our high degree of operational control, together with the large portion of
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our acreage that is held by production, and the speed with which we are able to drill and complete our wells in California gives us flexibility over the execution of our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production.
The following table summarizes certain information concerning our active producing and identified development assets as of December 31, 2022:
Acreage
Net Acreage Held By Production and Fee Interest(%)
Producing Wells, Gross(3)
Average Working Interest (%)(4)
Net Revenue Interest (%)(5)
Identified Drilling Locations(6)
Gross
Net(1)(2)
GrossNet
California
19,42115,09891 %2,214 97 %95 %8,527 7,186 
Utah
111,930101,49492 %1,232 96 %79 %1,286 1,209 
Total
131,351116,59292 %3,446 97 %88 %9,813 8,395 
__________
(1)    Represents our weighted-average interest in our acreage.     
(2)    Of which approximately 12% are BLM acres in California and 28% are BLM acres in Utah.
(3)    Includes 406 steamflood and waterflood injection wells in California and Utah.
(4)    Represents our weighted-average working interest in our active wells.
(5)    Represents our weighted-average net revenue interest for the year ended December 31, 2022.
(6)    Our total identified drilling locations include approximately 935 gross (928 net) locations associated with PUDs as of December 31, 2022, including 200 gross (198 net) steamflood injection wells. Please see “—Our Reserves—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations.
Our Reserves
Reserve Data
As of December 31, 2022, we had estimated total proved reserves of 110 mmboe, an increase from 97 mmboe, as of December 31, 2021. Our overall proved reserves increased 23 mmboe, or 24% in 2022, before production of 10 mmboe, the majority of which is due to extensions, as we added significant PUD locations throughout our properties. We replaced 236% of our 2022 production with additional proved reserves.
The majority of our reserves are composed of crude oil in shallow, long-lived reservoirs. As of December 31, 2022, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our proved reserves were approximately $2.1 billion and $2.6 billion, respectively. These values represent significant increases from the prior year end of $1.2 billion and $1.5 billion. PV-10 is a financial measure that is not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see in “—PV-10” below. As of December 31, 2022, approximately 76% of our proved reserves and approximately 85% of the PV-10 value of our proved reserves are derived from our assets in California. We also have approximately 24% of our proved reserves and approximately 15% of the PV-10 value in the Uinta basin in Utah, a mature, light-oil-prone play with significant undeveloped resources.
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The tables below summarize our estimated proved reserves and related PV-10 by category as of December 31, 2022:
Proved Reserves as of December 31, 2022(1)
Oil (mmbbl)Natural Gas (bcf)NGLs (mmbbl)
Total (mmboe)(2)
% of Proved% Proved Developed
Capex(3) ($MM)
PV-10(4) ($MM)
PDP46 38 5349 %86 %29 1,366 
PDNP— 9%14 %66 219 
PUD45 15 4843 %— %611 1,039 
Berry total proved reserves99 59 110100 %100 %706 2,624 
California total proved reserves 84 — — 84512 2,240 
__________
(1)    Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $100.25 per bbl Brent for oil and natural gas liquids (“NGLs”) and $6.40 per mmbtu Henry Hub for natural gas at December 31, 2022. The volume-weighted average realized prices over the lives of the properties were estimated at $91.33 per bbl of oil and condensate, $48.76 per bbl of NGLs and $6.76 per mcf of gas. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules, including adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Please see “—Our Reserves—PV-10” below.
(2)    Estimated using a conversion ratio of six mcf of natural gas to one bbl of oil.
(3)    Represents undiscounted future capital expenditures estimated as of December 31, 2022.
(4)    PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—Our Reserves—PV-10” below. PV-10 does not give effect to derivatives transactions.
The following table summarizes our estimated proved reserves and related PV-10 by area as of December 31, 2022. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton. The reserve estimates were prepared in accordance with current SEC rules and regulations regarding oil, natural gas and NGL reserve reporting. Reserves are stated net of applicable royalties.
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Proved Reserves as of December 31, 2022(1)
California
(San Joaquin basin)
Utah
(Uinta basin)
Total
Proved developed reserves:
Oil (mmbbl)43 11 54 
Natural gas (bcf)— 44 44 
NGLs (mmbbl)— 
Total (mmboe)(2)(3)
43 19 62 
Proved undeveloped reserves:
Oil (mmbbl)41 45 
Natural gas (bcf)— 15 15 
NGLs (mmbbl)— 
Total (mmboe)(3)
41 48 
Total proved reserves:
Oil (mmbbl)84 15 99 
Natural gas (bcf)— 59 59 
NGLs (mmbbl)— 
Total (mmboe)(3)
84 26 110 
PV-10 ($million)$2,240 $384 $2,624 
__________
(1)    Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $100.25 per bbl Brent for oil and NGLs and $6.40 per mmbtu Henry Hub for natural gas at December 31, 2022. The volume-weighted average realized prices over the lives of the properties were $91.33 per bbl of oil and condensate, $48.76 per bbl of NGLs and $6.76 per mcf. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For more information regarding commodity price risk, please see “Item 1A. Risk Factors—Risks Related to Our Operations and IndustryOil, natural gas and NGL prices are volatile and directly affect our results.
(2)    For proved developed reserves approximately 14% of total and 14% of oil are non-producing.
(3)    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 years ended December 31, 2022 and December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per mcf, respectively.
PV-10
PV-10 is a non-GAAP financial measure, which is widely used by the industry to understand the present value of oil and gas companies. It represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and does not give effect to derivative transactions or estimated future income taxes. Management believes that PV-10 provides useful information to investors because it is widely used by analysts and investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
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The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2022:
At December 31, 2022
(in millions)
California PV-10$2,240 
Utah PV-10384 
Total Company PV-102,624 
Less: present value of future income taxes discounted at 10%(550)
Standardized measure of discounted future net cash flows$2,074 
Proved Reserves Additions
Our overall proved reserves increased 23 mmboe, or 24%, before production. A majority of this increase was a result of adding extensions, as we added significant PUD locations throughout our properties. We replaced 236% of our production with additional proved reserves. The total changes to our proved reserves from December 31, 2021 to December 31, 2022 were as follows:
California
(San Joaquin basin)
Utah
(Uinta basin)
Colorado
(Piceance basin)
Total
(in mmboe)(1)
Beginning balance as of December 31, 202179 14 97 
Extensions and discoveries
20 — 26 
Revisions of previous estimates
(7)— (6)
Purchases of minerals in place(2)
— — 
Sales of minerals in place(3)
— — (4)(4)
Current year production
(8)(2)— (10)
Ending balance as of December 31, 202284 26 — 110 
__________
(1)    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 years ended December 31, 2022 and December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per mcf, respectively.
(2)    In February 2022, we acquired Antelope Creek in Utah.
(3)    In January 2022, we divested our Piceance basin properties in Colorado.
Extensions. During 2022, we added 26 mmboe of proved reserves from extensions in our California and Utah properties due to an increase in our proved acreage based on drilling results for the year.
Revisions of previous estimates.
Revisions related to price - Product price changes affect the proved reserves we record. For example, in certain price environments, higher prices can increase the economically recoverable reserves in our operations when the extra margin extends their expected life and renders more projects economic. Conversely, when prices drop, we can experience the opposite effects. In 2022, our total net positive price revision was one mmboe in California and one mmboe in Utah.
Other revisions - Other revisions can include upward or downward changes to previous proved reserves estimates due to the evaluation or interpretation of recent geologic, production decline or operating performance
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data. In 2022, we had negative other revisions of seven mmboe in California. The negative other revisions resulted primarily from a change in development plans in our thermal Diatomite in our North Midway-Sunset field.
Purchases of minerals in place. In February of 2022, we acquired Antelope Creek and we added seven mmboe of proved reserves in Utah.
Sale of minerals in place. In January of 2022, we divested our Piceance basin properties and removed approximately four mmboe of proved reserves in Colorado.
Current Year Production - Please refer to “Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCertain Operating and Financial Information” for discussion of our current year production.
Proved Undeveloped Reserves Changes
Our California proved undeveloped reserves increased nine mmboe in 2022 largely due to extensions, partially offset by revisions. The total changes to our proved undeveloped reserves from December 31, 2021 to December 31, 2022 were as follows:
California
(San Joaquin and Ventura basins)
Utah
(Uinta basin)(2)
Colorado
(Piceance basin)(3)
Total
(in mmboe)(1)
Beginning balance as of December 31, 202132 — 33 
Extensions and discoveries
19 — 25 
Revisions of previous estimates
(8)— — (8)
Reclassifications to proved developed
(2)— — (2)
Ending balance as of December 31, 202241 — 48 
__________
(1)    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 years ended December 31, 2022 and December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per mcf, respectively.
(2)    In February 2022, we acquired Antelope Creek of which all proved reserves were evaluated as proved developed.
(3)    In January 2022, we divested our Piceance basin properties in Colorado.
Extensions. During 2022, we added 25 mmboe of proved undeveloped reserves from extensions based on drilling results from unproven locations in Hill Tulare, McKittrick, and Utah due to an increase in our proved acreage based on drilling results for the year.
Revisions of previous estimates.
Other revisions - In 2022, we had negative other revisions of eight mmboe, primarily as a result of our change in development plans of our thermal Diatomite operations in our California North Midway-Sunset field.
Reclassifications to proved developed. Compared to recent years, in 2022, we shifted a large portion of our development efforts from drilling to workovers, sidetracks and recompletions, which have high returns and capital efficiency. Additionally, we transferred approximately two mmboe of proved undeveloped reserves to the proved developed category in 2022, in connection with our development drilling activity, spending approximately $30 million of capital. This 2022 capital intensity was higher than recent years as we increased our development focus in Utah based on the economic opportunities there, and Utah has deeper wells and thus higher drilling costs compared to California. The California development averaged under $11 per boe in 2022. We expect to have sufficient future
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capital to develop our proved undeveloped reserves at December 31, 2022 within five years. If prices decrease substantially below current levels for a prolonged period of time may we may be required to reduce expected capital expenditures over the next five years, potentially impacting either the quantity or the development timing of proved undeveloped reserves. Our year-end proved undeveloped reserves are determined in accordance with SEC guidelines for development within five years. Management has made the necessary commitment and we expect to have sufficient future capital to develop all of our proved undeveloped reserves. 
Reserves Evaluation and Review Process
Independent engineers, DeGolyer and MacNaughton (“D&M”), prepared our reserve estimates reported herein. The process performed by D&M to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by us. When preparing the reserve estimates, D&M did not independently verify the accuracy and completeness of the information and data furnished by us with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of D&M's work, something came to their attention that brought into question the validity or sufficiency of any such information or data, they would not rely on such information or data until they had satisfactorily resolved their related questions. The estimates of reserves conform to SEC guidelines, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Proved reserves estimates are established using standard geological and engineering technologies and computational methods, which are generally accepted by the petroleum industry. The proved reserves additions are primarily prepared by production history or analogy, which use historical production and analogous type curves that are based on decline curve analysis. We further establish reasonable certainty of our proved reserves estimates using geological and geophysical information to establish reservoir continuity between penetrations, downhole completion information, electrical logs, radioactivity logs, core analyses, available seismic data, and historical well cost, operating expense and commodity revenue data.
D&M also prepared estimates with respect to reserves categorization, using the definitions of proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
Our internal control over the preparation of reserves estimates is designed to provide reasonable assurance regarding the reliability of our reserves estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by our Executive Vice President of Business Development, who has a Masters in Geology from the University of South Carolina and a Bachelors in Geology from Carleton College, and more than 35 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, and presented to our Board of Directors. Within D&M, the technical person primarily responsible for reviewing our reserves estimates is a Licensed Professional Engineer in the State of Texas, has a Master of Science and Doctor of Philosophy degrees in Petroleum Engineering and has more than 10 years of experience in oil and gas reservoir studies and reserves evaluations.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured exactly. For more information, see “Item 1A. Risk Factors—Risks Related to Our Operations and IndustryEstimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.
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Determination of Identified Drilling Locations
Proven Drilling Locations
Based on our reserves report as of December 31, 2022, we have approximately 935 gross (928 net) drilling locations attributable to our proved undeveloped reserves. We increased our drilling locations attributable to proved undeveloped reserves in 2022, primarily due to an increase in our proved acreage based on drilling results. We use production data and experience gains from our development programs to identify and prioritize development of this proven drilling inventory. These drilling locations are included in our inventory only after they have been evaluated technically and are deemed to have a high likelihood of being drilled within a five-year time frame. As a result of technical evaluation of geologic and engineering data, it can be estimated with reasonable certainty that reserves from these locations are commercially recoverable in accordance with SEC guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local regulations and other factors it deems relevant in determining such locations.
Unproven Drilling Locations
We have also identified a multi-year inventory of 8,878 gross (7,467 net) unproven drilling locations as of December 31, 2022. Our unproven drilling locations are specifically identified on a field-by-field basis considering the applicable geologic, engineering and production data. We analyze past field development practices and identify analogous drilling opportunities taking into consideration historical production performance, estimated drilling and completion costs, spacing and other performance factors. These drilling locations primarily include (i) infill drilling locations, (ii) additional locations due to field extensions or (iii) thermal recovery project expansions, some of which are currently in the pilot phase across our properties, but have yet to be determined to be proven locations. We believe the assumptions and data used to estimate these drilling locations are consistent with established industry practices based on the type of recovery process we are using. Please see “Regulation of Health, Safety and Environmental Matters” for additional discussion of the laws and regulations that impact our ability to drill and develop our assets, including regulatory approval and permitting requirements.
We plan to analyze our acreage for exploration drilling opportunities at appropriate levels. We expect to use internally generated information and proprietary models consisting of data from analog plays, 3-D seismic data, open hole and mud log data, cores and reservoir engineering data to help define the extent of the targeted intervals and the potential ability of such intervals to produce commercial quantities of hydrocarbons.
Well Spacing Determination
Our well spacing determinations in the above categories of identified well locations are based on actual operational spacing within our existing producing fields, which we believe are reasonable for the particular recovery process employed (i.e., primary, waterflood and thermal recovery). Spacing intervals can vary between various reservoirs and recovery techniques. Our development spacing can be less than one acre for a thermal steamflood development in California.
Drilling Schedule
Our identified drilling locations have been scheduled as part of our current multi-year drilling schedule or are expected to be scheduled in the future. However, we may not drill our identified sites at the times scheduled or at all. We view the risk profile for our prospective drilling locations and any exploration drilling locations we may identify in the future as being higher than for our other proved drilling locations.
Our ability to drill and develop our identified drilling locations profitably or at all depends on a number of variables, many of which are outside of our control, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and permits, available transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. For a discussion of the risks associated with our drilling program,
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see “Item 1A. Risk Factors—Risks Related to Our Operations and IndustryWe may not drill our identified sites at the times we scheduled or at all.
The table below sets forth our proved undeveloped drilling locations and unproven drilling locations as of December 31, 2022.
PUD Drilling Locations
(Gross)
Unproven Drilling Locations (Gross)Total Drilling Locations (Gross)
Oil, Natural Gas Wells and Injection WellsOil, Natural Gas and Injection WellsOil, Natural Gas and Injection Wells
California847 7,680 8,527 
Utah88 1,198 1,286 
Total Identified Drilling Locations935 8,878 9,813 

The following tables sets forth information regarding production volumes for fields with equal to or greater than 15% of our total proved reserves for each of the periods indicated:

Year Ended December 31,
202220212020
SJV Midway Sunset
Total production(1):
Oil (mbbls)5,630 5,666 5,933 
Natural gas (bcf)— — — 
NGLs (mbbls)— — — 
Total (mboe)(2)
5,630 5,666 5,933 
Year Ended December 31,
202220212020
SJV Belridge Hill
Total production(1):
Oil (mbbls)1,551 1,505 1,280
Natural gas (bcf)— — — 
NGLs (mbbls)— — — 
Total (mboe)(2)
1,551 1,505 1,280


Year Ended December 31,
202220212020
Uinta
Total production(1):
Oil (mbbls)1,010 **
Natural gas (bcf)3,502 **
NGLs (mbbls)144 **
Total (mboe)(2)
1,737 
__________
*    Represented less than 15% of our total proved reserves for the periods indicated.
(1)    Production represents volumes sold during the period.
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(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 years ended December 31, 2022 and December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per mcf, respectively.
Productive Wells
As of December 31, 2022, we had a total of 3,450 gross (3,332 net) productive wells (including 406 gross and 405 net steamflood and waterflood injection wells), approximately 100% of which were oil wells. Our average working interests in our productive wells is approximately 97%. All of our Uinta basin oil wells produce associated gas and NGLs. We were participating in 16 steamflood projects and one waterflood project located in the San Joaquin basin, and one waterflood project located in the Uinta basin as of the end of 2022.
The following table sets forth our productive oil and natural gas wells (both producing and capable of producing) as of December 31, 2022.
California
(San Joaquin basin)
Utah
(Uinta basin)(3)
Total
Oil
Gross(1)
2,2151,2353,450
Net(2)
2,1441,1883,332
Gas(4)
Gross(1)
Net(2)
__________
(1)    The total number of wells in which interests are owned. Includes a total of 406 steamflood and waterflood injection wells with 395 in California and 11 in Utah.
(2)    The sum of fractional interests.
(3)    Includes wells in the Antelope Creek area that were acquired in February 2022.
(4)    In Utah we have associated gas in a portion of our oil wells, which are reported as oil wells.
Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2022.
California
(San Joaquin basin)
Utah
(Uinta)
Total
Developed(1)
Gross(2)
7,13546,98754,122
Net(3)
7,11045,22752,337
Undeveloped(4)
Gross(2)
12,28664,94377,229
Net(3)
7,98856,26764,255
__________
(1)    Acres spaced or assigned to productive wells.
(2)    Total acres in which we hold an interest.
(3)    Sum of fractional interests owned based on working interests or interests under arrangements similar to production sharing contracts.
(4)    Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the acreage contains proved reserves.
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Participation in Wells Being Drilled
As of December 31, 2022, we were not participating in any uncompleted wells.
Drilling Activity
The following table shows the net development wells we drilled during the periods indicated, which include delineation and temperature observation wells per our development plan. We did not drill any exploratory wells during the periods presented. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value.
California
(San Joaquin and Ventura basins(3))
Utah
(Uinta basin)
Colorado
(Piceance basin(4))
Total
2022
Oil(1)(2)
72 13 — 85
Natural Gas
— — — — 
Dry
— — — — 
2021
Oil(1)
181 10 — 191
Natural Gas
— — — — 
Dry
— — — — 
2020
Oil(1)(2)
45 — — 45
Natural Gas
— — — — 
Dry
— — — — 
__________
(1)    Includes injector wells.
(2)    Includes 12 and 50 wells that had not yet been connected to gathering systems in California in 2022 and 2020, respectively.
(3)    Effective October 2021, we completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles County, California, which included one well in 2020 and zero wells in 2021.
(4)    In January 2022, we divested our Piceance basin properties in Colorado.
Delivery Commitments
We have contractual agreements to provide gas volumes for processing, some of which specify fixed and determinable quantities and all of which were in Utah. As of December 31, 2022, the volumes contracted to be processed were approximately 4,560 mcf/d through March 2024. We have significantly more production than the amounts committed for delivery and have the ability to secure additional volumes of products as needed.
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Methods of Recovery and Marketing Arrangements
We seek to be the operator of our properties so that we can develop and implement drilling programs and optimization projects that not only replace production but add value through reserve and production growth and future operational synergies. We have an average of 97% working interest for operated wells and 98% operating control in our properties.
Our California operations are primarily focused on the thermal Sandstones, thermal Diatomite and Hill Diatomite development areas. We also have operations in the Uinta basin in Utah, as noted in the following table.
StateProject TypeWell TypeCompletion TypeRecovery Mechanism
California
Thermal SandstonesVertical / HorizontalPerforation/Slotted liner/gravel packContinuous and cyclic steam injection
California
Thermal DiatomiteVerticalShort interval perforationsHigh-pressure cyclic steam injection
California
Hill Diatomite (non-thermal)VerticalHydraulic stimulation, low intensity pin pointPressure depletion augmented with water injection
Utah
UintaVertical / HorizontalLow intensity hydraulic stimulationPressure depletion
Enhanced Oil Recovery
Most of our assets in California consist of heavy crude oil, which requires heat, supplied in the form of steam, injected into the oil producing formations to reduce the oil viscosity, thereby allowing the oil to flow to the wellbore for production. We have cyclic and continuous steam injection projects in the San Joaquin basin, all in Kern County and in fields such as Midway-Sunset, South Belridge, McKittrick, and Poso Creek. This technique has many years of demonstrated success in thousands of wells drilled by us and others. Historically, we start production from heavy oil reservoirs with cyclic injection and then expand operations to include continuous injection in adjacent wells. We intend to continue employing both recovery techniques as long as a favorable oil to gas price spread exists. Full development of these projects typically takes multiple years and involves upfront infrastructure construction for steam and water processing facilities and follow on development drilling. These thermal recovery projects are generally shallower in depth (600 to 2,500 ft) than our other programs and the wells are relatively inexpensive to drill and complete at approximately $500,000 per well. Therefore, we can normally implement a drilling program quickly with attractive rates of return.
Cogeneration Steam Supply and Conventional Steam Generation
We produce oil from heavy crude reservoirs using steam to heat the oil so that it will flow to the wellbore for production. To assist in this operation, we own and operate four natural gas burning cogeneration plants that produce electricity and steam: (i) a 38 MW facility (“Cogen 38”), an 18 MW facility (“Cogen 18”) and a 5 MW facility (“Pan Fee Cogen”), each located in the Midway-Sunset Field and (ii) another 5MW facility (“21Z Cogen”) located in the McKittrick Field. Cogeneration plants, also referred to as combined heat and power plants, use hot turbine exhaust to produce steam while generating electrical power. This combined process is more efficient than producing power or steam separately. For more information please see “—Electricity.” and “Item 1A. Risk Factors—Risks Related to Our Operations and IndustryWe are dependent on our cogeneration facilities to produce steam for our operations. Contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.
We own 62 fully permitted conventional steam generators. The number of generators operated at any point in time is dependent on (i) the steam volume required to achieve our targeted injection rate and (ii) the price of natural gas compared to our oil production rate and the realized price of oil sold. Ownership of these varied steam generation facilities allows for maximum operational control over the steam supply, location and, to some extent, the
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aggregated cost of steam generation. The natural gas we purchase to generate steam and electricity is primarily based on Rockies price indexes, including transportation charges, as we currently purchase a substantial majority of our gas needs from the Rockies, with the balance purchased in California.
Marketing Arrangements
We market crude oil, natural gas, NGLs, gas purchasing and electricity.
Crude Oil. Approximately 92% of our California crude oil production is connected to California markets via crude oil pipelines. We generally do not transport, refine or process the crude oil we produce and do not have any long-term crude oil transportation arrangements in place. California oil prices are Brent-influenced as California refiners import approximately 70% of the state’s demand from OPEC+ countries and other waterborne sources. This dynamic has led to periods, including recent years, where the price for the primary benchmark, Midway-Sunset, a 13° API heavy crude, has been equal to or exceeded the price for WTI, a light 40° API crude. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low transportation costs, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California. Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to purchaser-posted prices for the producing area. We sell all of our oil production under short-term contracts. The waxy quality of oil in Utah has historically limited sales primarily to the Salt Lake City market, which is largely dependent on the supply and demand of oil in the area. The recent success of a tight oil play in the basin has increased supply and put downward pressure on physical oil prices. Due to these circumstances, we are endeavoring to sell our crude to markets outside the basin. Export options to other markets via rail are available and have been used in the past, but are comparatively expensive. We also entered into oil hedges to protect our operating expenses and other costs from price fluctuations.
Natural Gas. Our natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area. Our natural gas production is sold to purchasers under seasonal spot price or index contracts. We sell all of our natural gas and NGL production under short-term contracts at market-sensitive or spot prices. In certain circumstances, we have entered into natural gas processing contracts whereby the residual natural gas is sold under short-term contracts but the related NGLs are sold under long-term contracts. In all such cases, the residual natural gas and NGLs are sold at market-sensitive index prices.
NGLs. We do not have long-term or long-haul interstate NGL transportation agreements. We sell substantially all of our NGLs to third parties using market-based pricing. Our NGL sales are generally pursuant to processing contracts or short-term sales contracts.
Gas Purchasing. We enter into hedges for gas purchases to protect our operating expenses from price fluctuations. We also have long-term pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that help reduce our exposure to fuel gas purchase price fluctuations.
Electricity Generation. Our cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. The total nameplate electrical generation capacity of our four cogeneration facilities, which are centrally located on certain of our oil producing properties, is approximately 66 MW. The steam generated by each facility is capable of being delivered to numerous wells that require steam for our thermal recovery processes. The main purpose of the cogeneration facilities is to reduce the steam and electricity costs in our heavy oil operations.
Electricity and steam produced from our Pan Fee Cogen and 21Z Cogen facilities are used solely for field operations.

For the year ended December 31, 2022, we sold approximately 1,005 megawatt-hours (“MWhs”) per day of cogeneration power into the grid and on average consumed approximately 293 MWhs per day of cogeneration power for lease operations. The four cogeneration facilities produced an average of approximately 24,000 barrels of
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steam per day. Contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.
Electricity Sales Contracts. We sell electricity produced by one of our cogeneration facilities under a long-term PPA approved by the California Public Utilities Commission (the “CPUC”) to a California investor-owned utility, Pacific Gas and Electric (“PG&E”). The PPA expires in November 2026.
Principal Customers
For the year ended December 31, 2022, sales to PBF Holding, Tesoro Refining and Marketing, and Phillips 66, accounted for approximately 33%, 16%, and 10%, respectively, of our sales. At December 31, 2022, trade accounts receivable from three customers represented approximately 33%, 16%, and 13% of our receivables.
If we were to lose any one of our major oil and natural gas purchasers, the loss could cease or delay production and sale of our oil and natural gas in that particular purchaser’s service area and could have a detrimental effect on the prices and volumes of oil, natural gas and NGLs that we are able to sell. For more information related to marketing risks, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry”.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a preliminary review of the title to our properties at the time of acquisition. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. We do not commence drilling operations on a property until we have cured known title defects on such property that are material to the project. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations, or net profits interests.
Competition
The oil and natural gas industry is highly competitive. In our upstream E&P business, we historically encounter strong competition from other companies, including independent operators in acquiring properties, contracting for drilling and other related services, and securing trained personnel. We also are affected by competition for drilling rigs and related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. The lower-cost, commoditized nature of our equipment and service providers partially insulates us from the cost inflation pressures experienced by producers in unconventional plays. We are unable to predict when, or if, such shortages may occur or how they would affect our drilling program.
Through CJWS we provide services in the California market where our competitors are comprised of both small regional contractors as well as larger companies with international operations. CJWS’ revenues and earnings can be affected by several factors, including changes in competition, fluctuations in drilling and completion activity by its customers, perceptions of future prices of oil and gas, government regulation, disruptions caused by weather, pandemics and general economic conditions. We believe that the principal competitive factors are price, performance, service quality, safety, and response time. For more information regarding competition and the related risks in the oil and natural gas industry, please see “Item 1A. Risk Factors—Risks Related to Our Operations and IndustryCompetition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.
We also face indirect competition from alternative energy sources, such as wind or solar power, and these alternative energy sources could become even more competitive as California and the federal government develop renewable energy and climate-related policies.
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Seasonality
Seasonal weather conditions have in the past, and in the future likely will, impact our drilling, production and well servicing activities. Extreme weather conditions can pose challenges to meeting well-drilling and completion objectives and production goals. Seasonal weather can also lead to increased competition for equipment, supplies and personnel, which could lead to shortages and increased costs or delayed operations. Our operations have been, and in the future could be, impacted by ice and snow in the winter, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as by wildfires and rain. Additionally, unusually heavy rains or extreme temperatures can cause flooding and power outages which could adversely impact our ability to operate, particularly in California. For example, in December of 2022, unusually poor weather caused operational challenges, production downtime, and much higher natural gas prices in California. The extreme, adverse weather conditions have continued in the first quarter of 2023 and impacted our production.
Among other factors, extreme cold weather conditions drove high natural gas prices in 2022. In California we experienced a significant increase in mid-December 2022, with gas prices briefly as high as $50.79 per mmbtu. We quickly pivoted and reduced our gas consumption in California by temporarily shutting-down one of our cogeneration facilities and reducing steam generation in other parts of our operation, which negatively impacted production. We seek to mitigate a substantial portion of the gas purchase exposure for our cogeneration plants by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. Aside from the impact gas prices have on electricity prices, these sales are generally higher in the summer months as they include seasonal capacity amounts. Based on market prices and current and projected supply and demand balances, our current expectation is that natural gas prices in California will continue to remain elevated through the first half of 2023 and begin to weaken in the middle of 2023. Our hedging strategy coupled with our midstream access to gas from the Rockies also helps mitigate the impact of the high natural gas prices on our cost structure.
Regulatory Matters
Regulation of the Oil and Gas Industry
Like other companies in the oil and gas industry, our operations are subject to a wide range of complex federal, state and local laws and regulations. California, where most of our operations and assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations. A combination of federal, state and local laws and regulations govern most aspects of exploration, development and production in California, including:
oil and natural gas production, including siting and spacing of wells and facilities on federal, state and private lands with associated conditions or mitigation measures;
methods of constructing, drilling, completing, stimulating, operating, inspecting, maintaining and abandoning wells;
the design, construction, operation, inspection, maintenance and decommissioning of facilities, such as natural gas processing plants, power plants, compressors and liquid and natural gas pipelines or gathering lines;
techniques for improved or enhanced recovery, such as steam or fluid injection for pressure management;
the sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and improved or enhanced recovery processes;
the posting of bonds or other financial assurance to drill, operate and abandon or decommission wells and facilities; and
the transportation, marketing and sale of our products.
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Collectively, the effect of the existing laws and regulations is to potentially limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, and reduce the amount of oil and natural gas that we can produce from our wells below levels that would otherwise be possible. Additionally, the regulatory burden on the industry increases our costs and consequently may have an adverse effect upon operations, capital expenditures, earnings and our competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns, reputational damage, 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.
The California Department of Conservation’s Geologic Energy Management Division (“CalGEM”) is California's primary regulator of the oil and natural gas drilling and production activities on private and state lands, with additional oversight from the California State Lands Commission’s administration of state surface and mineral interests, as well as other state and local agencies. The Bureau of Land Management (“BLM”) of the U.S. Department of the Interior exercises similar jurisdiction on federal lands in California, on which CalGEM also asserts jurisdiction over certain activities. The California Legislature has significantly increased the jurisdiction, duties and enforcement authority of CalGEM, the State Lands Commission and other state agencies with respect to oil and natural gas activities in recent years, and CalGEM and other state agencies have also significantly revised their regulations, regulatory interpretations and data collection and reporting requirements. In addition, from time to time legislation has been introduced in the California State Legislature seeking to further restrict or prohibit certain oil and gas operations, and the U.S. Congress and federal agencies also regularly seek to revise environmental laws and regulations.
A discussion of the potential impact that government regulations, including those regarding environmental matters, may have upon our business, operations, capital expenditures, earnings and competitive position follows. For more information related to the regulatory risks that could potentially have a material effect on the Company, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry”.
California Permitting Considerations
The issuance of permits and other approvals for drilling and production activities by state and local agencies or by federal agencies may be subject to environmental reviews under the California Environmental Quality Act (“CEQA”) or the National Environmental Policy Act (“NEPA”), respectively, which in the past has resulted, and in the future may result, in delays in the issuance of necessary permits and approvals and the imposition of onerous mitigation measures or restrictions, among other things. For example, before an operator can pursue drilling operations in California, they must first obtain local government permission to engage in an oil and gas production land use, which requires the local government to conduct a CEQA-compliant review to evaluate the environmental impact that the proposed land use may cause, including on habitat, neighboring communities, air quality, water quality, and other environmental considerations. CEQA imposes similar obligations on permitting decisions by state and local agencies. Prior to issuing the permits necessary for the conduct of certain operations (for example, to drill a new well), CalGEM requires an operator to identify the manner in which CEQA has been satisfied, which is typically through either an environmental impact review or an exemption by a state or local agency.
Over the last few years, there has been a number of developments at both the California state and local levels that resulted in delays in the issuance of new drilling permits for oil and gas activities in Kern County where all of our California assets are located, as well as a more time- and cost-intensive permitting process. Most notably, in Kern County, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (an “EIR”) covering oil and gas operations in Kern County (the “Kern County EIR”). In 2020, a lawsuit was filed challenging the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County made certain revisions to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County prepared a supplemental EIR (the “Supplemental EIR”) which was approved by the Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs, a Kern County
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Superior Court judge suspended use of the Supplemental EIR in October 2021 pending further review by the Court. In June 2022, the Kern County Superior Court ruled in favor of Kern County in part but also found that the Supplemental EIR still failed to meet the minimum requirements of CEQA. In August 2022, the Kern County Board of Supervisors approved changes which addressed four discrete issues identified by the court in its June 2022 ruling. The Kern County Superior Court subsequently issued a ruling in October 2022 determining that the Kern County Supplemental EIR was not decertified, but ordered Kern County to address the four discrete issues previously identified before the Supplemental EIR could become effective. Kern County then filed notice with the court of the changes and on November 2, 2022, the trial court lifted the order preventing reliance on the Supplemental EIR. In December 2022, the Kern County Superior Court denied a motion to stay this action and the plaintiffs appealed. On January 26, 2023, the California Fifth District Court of Appeal issued a preliminary order which again suspended use of the Supplemental EIR to meet CEQA requirements pending the outcome of a final order on Kern County’s ability to rely on the Supplemental EIR during the appeals process. While the court has not issued a final order to date, it is possible that use of the Supplemental EIR will remain suspended through the duration of the appeals process, which would result in significant ongoing disruption to the permitting process in Kern County for an extended period of time. Furthermore, if the Supplemental EIR is ultimately determined to be deficient upon resolution of the appeals process, use of the Supplemental EIR to satisfy CEQA requirements for drilling permits may be suspended until such deficiencies are resolved, which could extend such disruptions for the foreseeable future. In addition, CalGEM provided notice to operators on February 2, 2023 that, in light of the preliminary order, it would no longer recognize job cards issued by Kern County as CEQA lead agency in reliance on the Supplemental EIR between November 2, 2022 and January 26, 2023 (the “CalGEM Notice”). Even if the California Fifth District Court of Appeal lifts the suspension on reliance on the Supplemental EIR, there is no assurance that we will be able to use the job cards issued by Kern County during that period or how quickly any new permits may be issued by CalGEM.
Separately, in February 2021, the Center for Biological Diversity filed suit against CalGEM alleging that its reliance on the Kern County EIR for oil and gas decisions violates CEQA, and that an independent environmental impact review in compliance with CEQA is required by CalGEM before the agency can issue oil and gas permits and approvals. Most recently, the Alameda County Superior Court denied CalGEM’s motion for judgment on the pleadings and the lawsuit remains ongoing. We cannot predict its ultimate outcome or whether it could result in changes to the requirements for demonstrating compliance with CEQA and permitting process, even if the Supplemental EIR is ultimately deemed sufficient and reinstated.
As a result of this ongoing uncertainty, we have experienced significant delays in the issuance of permits for new wells by CalGEM. CalGEM has not issued any new drill permits to any producer since December 2022. Until Kern County is able to resume the ability to utilize the Supplemental EIR to demonstrate CEQA compliance, our ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating compliance with CEQA to CalGEM. We were able to secure some new drill permits in 2022 from CalGEM in specific operational areas where we did not have to rely on the Kern County EIR because the CEQA environmental analyses had already been separately completed by a predecessor entity, which CalGEM recognized as satisfying the CEQA compliance obligation. We believe we may have the ability to procure additional permits within these operational areas in 2023. Demonstrating CEQA compliance without being able to reference the Supplemental EIR 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.
At this time, we expect greater than 90% of our planned 2023 production will come from our base production, with the remainder from workovers, sidetracks and other activities related to existing wellbores, as well as from limited number of new wells drilled during the year for which we already have permits or expect to receive permits because the wells are in areas where CEQA analysis has already been completed. As a result of the CalGEM Notice and the Kern County EIR legal challenges, our current capital budget for 2023 has been prepared on the assumption that no additional permits for new wells will be issued in 2023 in areas for which CEQA analysis has not already been completed separate from the currently suspended Kern County EIR. However, we are pursuing other avenues to obtain additional permits for new wells that, if received could enable us to expand the 2023 drilling program contemplated under our capital budget.
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Among other things, if we are unable to obtain new well drill permits through 2024, it could result in the loss of some amount of the proved undeveloped reserves that expire on December 31, 2024 identified in our December 31, 2022 reserve report.
Setbacks
Separately, on September 16, 2022, the California Governor signed into law Senate Bill No. 1137 which prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks effective January 1, 2023. On January 6, 2023, CalGEM’s emergency regulations to support implementation of Senate Bill No. 1137 were approved by the Office of Administrative Law and final regulations were published. The regulations include applicable requirements of notice to property owners and tenants regarding the work performed and offering the sampling of test water wells or surface water before and after drilling; the contents of required notices for new production facilities; the annual submission of a sensitive receptor inventory and sensitive receptor map and the contents and format of the same; and the requirements of statements where operators have determined a location not to be within a health protection zone. Additional provisions of Senate Bill No. 1137, include, among others, the imposition of HSE 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. The latter provisions are effective January 1, 2025.
In December 2022, proponents of a voter referendum (the Referendum) collected more than the requisite number of signatures required to put Senate Bill No. 1137 on the 2024 ballot. On February 3, 2023, the Secretary of State of California certified the signatures and confirmed that the Referendum qualifies for the November 2024 ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote, although any stay could be delayed if there are legal challenges to the Secretary of State’s certification. However, we cannot predict any future actions by CalGEM, the State of California, or other interested parties may take that could further limit our ability to drill in certain areas.
The majority of our production is in rural areas in the San Joaquin basin and is unlikely to be affected by Senate Bill No. 1137 should it permanently stay effective. We are actively pursuing mitigation efforts with respect to the potential impacts on current and planned wells, but it is possible that we are unable to ultimately develop those properties. We continue to assess the impacts of this rule, but we currently estimate that approximately 13% of our overall proved reserves are within the setbacks established by Senate Bill No. 1137. We do not expect this law to result in any material change in our overall existing proved developed producing reserves or current production rates.
California Underground Injection Control Regulations
The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program promulgated under the SDWA and relevant state laws regulate the drilling and operation of injection and disposal wells that manage produced water (brine wastewater containing salt and other constituents produced by oil and natural gas wells). Permits must be obtained before developing and using deep injection wells for the disposal of produced water or for enhanced oil recovery, and well casing integrity monitoring must be conducted periodically to ensure the well casing is not leaking produced water to groundwater. The EPA directly administers the UIC program in some states, and in others, such as California, administration is delegated to the state.
Effective April 2019, CalGEM finalized new UIC regulations, which affects specific types of wells: (i) those that inject water or steam for enhanced oil recovery and (ii) those that return the briny groundwater that comes up from oil formations during production. The key regulations include stronger testing requirements designed to identify potential leaks, increased data requirements to ensure proposed projects are fully evaluated, continuous well pressure monitoring, requirements to automatically cease injection when there is a risk to safety or the environment, and requirements to disclose chemical additives for injection wells close to water supply wells. Notwithstanding these changes, separately, in September 2021 the U.S. Environmental Protection Agency (“EPA”) issued a letter to
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the California Natural Resources Agency and the State Water Resources Control Board regarding California’s compliance with a 2015 compliance plan relating to the State’s process for approving aquifer exemptions under the UIC regulations and submitting those approvals to EPA for review. The letter requested that California take appropriate action by September 2022, or the EPA would consider taking additional action to impose limits on California’s administration of the UIC program, withhold federal funds for the administration of the UIC program, and direct orders to oil and gas operators injecting into formations not authorized by the EPA, amongst other measures. The State responded in October 2021 with a proposed compliance plan and a follow-up letter in August 2022 providing a mid-year update, but, to date, the EPA has not yet responded. Additional limitations on injection well operations increased federal oversight of the UIC permitting process, or a lack of funds for California to administer permits under the UIC program all have the potential to adversely affect our operations and result in increased operational and compliance costs.
Uncertainty surrounding compliance with UIC regulations has from time to time resulted in delays in obtaining UIC permits for enhanced oil recovery, disposal of oilfield wastes and injection wells, which in turn can delay our ability to obtain other permits needed to conduct our planned operations. Moreover, concerns related to potential groundwater contamination issues have resulted in increased scrutiny with respect to UIC permitting and other oil and gas activities in California. It is possible that more stringent regulations or restrictions on our ability to obtain UIC permits for enhanced oil recovery and disposal of oilfield wastes could be imposed upon our operations in the future. Additionally, CalGEM has indicated that is coordinating with the California State Water Resources Control Board to propose rules regarding enhanced reviews for injection well permitting decisions. Any such changes could adversely impact our operations. For example, while “infill drilling” has been considered exempt from certain CalGEM permitting requirements in the past, such as the need to obtain a new project approval letter (“PAL“), CalGEM appears to be limiting the instance where it considers proposed drilling as “infill” of areas already given over to oilfield uses and impacts. An infill well occurs when an operator seeks to change the location of an active injection well or add a new injection well not previously identified in the project application. In March 2022, CalGEM issued a Notice to Operators informing operators of new checklist documentation used in connection with the approval of injection wells, which includes adding non-expansion infill wells. Changes in the process for approving infill wells has the potential to delay permitting injection and other activities, and could result in increased compliance costs on our operations. Our 2023 plans, as well as our future plans, may be impacted by an inability to timely obtain certain permits needed to carry out our drilling and development plans due to a delay in obtaining the requisite UIC permits. In the past, we have been able to modify our drilling and development plans and obtain the permits necessary to support ongoing operations despite these permitting uncertainties, but there is no guarantee that we can continue to successfully manage these issues in the future.
California Idle Well Regulations
In California, an idle well is one that has not been used for two years or more and has not yet been permanently sealed pursuant to CalGEM regulations. An idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as an orphan well. In April 2019, CalGEM issued updated idle well regulations, including a comprehensive well testing regime to demonstrate the mechanical integrity of idle wells, a compliance schedule for testing or plugging and abandoning idle wells, the collection of data necessary to prioritize testing and plugging idle wells that will not return to service, an engineering analysis for each well idled 15 years or longer, and requirements for active observation wells. Additionally, operators are required to either submit annual idle well management plans describing how they will plug and abandon or reactivate a specified percentage of long-term idle wells or pay additional annual fees and perform additional testing to retain greater flexibility to return long-term idle wells to service in the future. Also, in 2019, the Governor of California signed AB 1057, legislation requiring CalGEM to study and prioritize idle wells with emissions, evaluate costs of abandonment, decommissioning and restoration, and review and update associated indemnity bond amounts from operators if warranted, up to a specified cap. This legislation also expanded CalGEM’s duties, effective January 1, 2020, to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs.
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To date, we have fulfilled the conditions of our prior idle well management plans and we will do so again in 2023 based on the submitted plan. In 2022, we spent approximately $20 million on our plugging and abandonment activities. In 2023, we currently estimate spending will be approximately $21 million to $24 million for such activities in order to meet our annual plugging and abandonment obligations.
Additionally, in the fourth quarter of 2021, we acquired CJWS and started a profitable new business line to provide standard well services to the industry in California, including plugging and abandoning idle wells across California for ourselves and other operators, as well as the State of California. We believe that CJWS is well positioned to capture both state and federal funds to help remediate idle wells; there are approximately 35,000 idle wells estimated to be in California according to third-party sources.
Additional Actions Impacting Oil and Gas Activities in California
In recent years the California Governor and Legislature have taken a series of actions that seek to reduce both the supply of and demand for fossil fuels in the state. For example, in September 2022, the Governor signed Senate Bill No. 1279 into law, which codifies an executive order previously issued by the Governor’s Office requiring the state to achieve carbon neutrality by 2045. In addition, Governor Newsom previously issued an executive order that established several goals and directed several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: phasing out the sale of emissions-producing vehicles; developing strategies for the closure and repurposing of oil and gas facilities in California; and calling on the California State Legislature to enact new laws prohibiting hydraulic fracturing in the state by 2024 (we currently do not perform any hydraulic fracturing in California and our near term plans do not include the development of assets requiring hydraulic fracturing).
Separately, in October 2020, the California Governor issued an executive order that established a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directed state agencies to implement other measures to mitigate climate change and strengthen biodiversity. At this time, we cannot predict the potential future actions that may result from this order or how such may potentially impact our operations.
Additionally, President Biden signed the Inflation Reduction Act (“IRA”) into law on August 16, 2022 which, among other things, imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector and provides significant incentives for renewable energy and low or zero carbon products. 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.
Restrictions on Oil and Gas Developments on Federal Lands
As of December 31, 2022, approximately 12% and 28% of our net acreage in California and Utah, respectively, is on federal land, which comprises approximately 10% and 12% of our total proved reserves in California and Utah, respectively, and approximately 8% and 7% of our PUD locations in California and Utah, respectively. Additional federal restrictions on oil and gas activities on federal lands may be imposed in the future. For example, on January 27, 2021, President Biden issued an executive order that suspends the issuance of new leases for oil and gas development on federal lands to the extent permitted by law and calls for a review of existing leasing and permitting practices for such activities on federal lands (the order clarifies that it does not restrict such operations on tribal lands including tribal lands that the federal government merely holds in trust). Although the order does not apply to existing operations under valid leases, we cannot guarantee that further action will not be taken to curtail oil and gas development on federal land. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021 and a permanent injunction in August 2022, effectively halting implementation of the leasing suspension with respect to leases canceled or postponed prior to March 24, 2021. Separately, the Department of the Interior (“DOI”) released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil
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and gas leasing program, including prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. The IRA responded to one of the report’s recommendations and increased onshore royalty rates to 16⅔%. Several of the report’s other recommendations, however, will require further Congressional action and we cannot predict to the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities could result in increased costs and adversely impact our operations.
With respect to major federal actions pursuant to NEPA, recent modifications may also impose further restrictions on oil and gas activities on federal lands. In October 2021, the Biden Administration announced three significant changes to a 2020 rule finalized under the Trump Administration. These changes included authorizing agencies to consider the direct, indirect and cumulative effects of major federal actions including upstream and downstream GHG emissions impacts of fossil fuel projects, allowing agencies to determine the purpose and need of a project (thereby allowing consideration of less-harmful alternatives), and affording agencies greater flexibility in crafting their own NEPA procedures, consistent with Council of Environmental Quality (“CEQ”) regulations, so as to meet the agencies’ and public’s needs. To that end, in April 2022, the CEQ issued a final rule in line with the proposed changes, a move considered as “Phase I” of the Biden Administration’s two-phased approach to modifying NEPA. “Phase 2” of this process includes the release of a new rule proposing broader changes to NEPA regulations.
Operations on Tribal Lands
As of December 31, 2022, approximately 65% of our net acreage in Utah is on tribal lands, which comprises approximately 69% of our total proved reserves in Utah, and approximately 88% of our PUD locations in Utah; none of our California assets or operations are located on tribal lands. In addition to potential regulation by federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations promulgated by the Indian tribe with jurisdiction over such lands applies to lessees, operators and other parties on such lands, tribal or allotted. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment and contractor preferences and numerous other matters. Further, lessees and operators on tribal lands may be subject to the jurisdiction of tribal courts, unless there is a specific waiver of sovereign immunity by the relevant tribe allowing resolution of disputes between the tribe and those lessees or operators to occur in federal or state court. These laws, regulations and other issues present unique risks that may impose additional requirements on our operations, cause delays in obtaining necessary approvals or permits, or result in losses or cancellations of our oil and natural gas leases, which in turn may materially and adversely affect our operations on tribal lands.
Restrictions on High-Pressure Cyclic Steam and Well Stimulation Treatments
Our California operations are primarily focused on the thermal Sandstones, thermal Diatomite and Hill Diatomite development areas, of which only our undeveloped thermal Diatomite assets require new high-pressure cyclic steam wells and Belridge Hill Diatomite potentially require well stimulation treatments (“WST”) (also known as hydraulic stimulation, hydraulic fracturing or fracking). We have limited our plan in 2023 for our undeveloped thermal Diatomite assets and we do not have any near term plans that would require WST in our Belridge Hill Diatomite assets. We do rely on other methods of well stimulation and injection, including the use of cyclic and continuous steam injection, which is heavily regulated. Any restrictions on the use of those well stimulation treatments or other forms of injection may adversely impact our operations, including causing operational delays, increased costs, and reduced production. However, our ability to conduct such activities has not been prohibited or otherwise restricted by the moratorium on permitting for new high–pressure cyclic steam wells and WST.
As referenced above, in November 2019, the State Department of Conservation issued a press release announcing three actions by CalGEM: (1) a moratorium on approval of new high–pressure cyclic steam wells pending a study of the practice to address surface expressions experienced by certain operators; (2) a review and update of regulations regarding public health and safety near oil and natural gas operations pursuant to additional duties assigned to CalGEM by the California State Legislature in 2019 (discussed above); (3) a performance audit of CalGEM's permitting processes for issuing WST permits and project approval letters (“PALs”) for underground injection activities by the State Department of Finance; and (4) an independent review of the technical content of
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pending WST and PAL applications by Lawrence Livermore National Laboratory. In September 2020, the Governor of California issued an executive order which, among other actions, required CalGEM to complete its public health and safety review and propose additional regulations and noted the Governor’s intent to seek legislation to end the issuance of new hydraulic fracturing permits by 2024; the executive order is further discussed above under “- Additional Actions Impacting Oil and Gas Activities in California.” In January 2020, CalGEM issued a formal notice to operators, including us, that they had issued restrictions imposing the previously announced moratorium to prohibit new underground oil-extraction wells from using high-pressure cyclic steaming process. In February of 2022, CalGEM issued letters to operators who had conducted high pressure cyclic steam operations in the past, indicating that CalGEM intended to revisit the moratorium on a field-by-field basis, but no further guidance has yet been received by us to date. Importantly, the moratorium on high-pressure cyclic steam injection did not impact existing production or previously approved permits and our plans and operations have not been materially impacted to date. In 2023 we have plans to drill permitted wells in these thermal diatomite properties.
Historically, state regulators have overseen hydraulic stimulation operations as part of their oil and natural gas regulatory programs. However, from time to time, federal agencies have asserted regulatory authority over certain aspects of the process. In 2016, the EPA issued final regulations regarding, among other things, certain hydraulic stimulation activities involving the use of diesel fuels and standards for the capture of air emissions released during hydraulic stimulation. And while the BLM previously rescinded regulations imposing certain requirements on hydraulic fracturing on federal lands in 2017, the rescission is subject to ongoing legal challenge and the regulations may be reconsidered under the Biden Administration. Relatedly, the Biden Administration has released proposed rules mandating that operators maintain leak detection and repair plans for operations on federal or Native American leased land and, in November 2022, proposed a rule that would limit flaring from well sites on federal lands as well as allow the delay or denial of permits if the agency finds an operator’s methane waste minimization plan insufficient. The outcome of these rules could materially impact our operations in the Uinta basin, where as of December 31, 2022, approximately 12% of our proved reserves in Utah were located on federal lands and approximately 69% were located on tribal lands. In addition, from time to time legislation has been introduced before Congress that would provide for federal regulation of hydraulic stimulation and would require disclosure of the chemicals used in the stimulation process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic stimulation operations as well as various restrictions on those operations. These permitting requirements and restrictions could materially impact our operations in the Uinta basin, including due to delays in operations at well sites and also increased costs to make wells productive.
Water Resources
Oil and gas exploration and development activities can be adversely affected by the availability of water. Drought conditions, competing water uses and other physical disruptions to our access to water could adversely affect our operations. In recent years, California and Utah have experienced persistent and severe drought conditions. As a result water districts and the California state government have implemented regulations and policies that may restrict groundwater extraction and water usage and increase the cost of water. Various local governments in Utah have implemented water restrictions too. Water management, including our ability to recycle, reuse and dispose of produced water and our access to water supplies from third-party sources, in each case at a reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential component of our operations. As such, any limitations or restrictions on wastewater disposal or water availability could have an adverse impact on our operations. We treat and reuse water that is co-produced with oil and natural gas for a substantial portion of our needs in activities such as pressure management, steam flooding and well drilling, completion and stimulation. We use water supplied from various local and regional sources, particularly for power plants and to support operations like steam injection in certain fields. While our production to date has not been materially impacted by restrictions on access to third-party water sources, we cannot guarantee that there may not be restrictions in the future.
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Regulation of Health, Safety and Environmental Matters
The federal health, safety and environmental laws and regulations applicable to us and our operations include, among others, the following:
Occupational Safety and Health Act (“OSHA”), which governs workplace safety and the protection of the safety and health of workers;
Clean Air Act (the “CAA”), which restricts the emission of air pollutants from many sources through the imposition of air emission standards, construction and operating permitting programs and other compliance requirements;
Clean Water Act (the “CWA”), which restricts the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined to include, among other things, certain wetlands;
The Oil Pollution Act of 1990, which amends and augments the CWA and imposes certain duties and liabilities related to the prevention of oil spills and damages resulting from such spills;
Safe Drinking Water Act (“SDWA”), which, amongst other matters, regulates the drilling and operation of injection and disposal wells that manage produced water;
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes strict, joint and several liability where hazardous substances have been released into the environment (commonly known as “Superfund”);
U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates the safe and secure transportation of energy, including, with some specific exceptions, natural gas pipelines;
Energy Independence and Security Act of 2007, which prescribes new fuel economy standards, mandates for production of renewable fuels and other energy saving measures, which can indirectly affect demand for our products;
National Environmental Policy Act (“NEPA”), which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands;
Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste (broadly defined to include liquid and gaseous waste as well);
DOI regulations, which impose requirements on oil and gas production activities on federal lands and establish liability for pollution cleanup and damages; and
Endangered Species Act, which restricts activities that may affect endangered and threatened species or their habitats.
Federal, state and local agencies may assert overlapping authority to regulate in these areas. The State of California imposes additional laws that are analogous to, and often more stringent than, the federal laws listed above. Among other requirements and restrictions, these laws and regulations:
require the acquisition of various permits, approvals and mitigation measures before drilling, workover, production, underground fluid injection, enhanced oil recovery methods or waste disposal commences, or before facilities are constructed or put into operation;
establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, conduct regional, community or field monitoring of air, soil or water quality, and require attainment plans to meet those regional standards, which may include significant mitigation measures or restrictions on development, economic activity and transportation in such region;
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impose, on federal, state, and local jurisdiction lands, comprehensive environmental analyses, recordkeeping and reports with respect to operations including preparation of various environmental impact assessments for certain operations;
require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and control systems, and implementation of inspection, monitoring and repair programs to prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;
restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation and reclamation measures;
restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced water or wastes, that can be released or discharged into the environment in connection with drilling and production activities, or any other uses of those materials resulting from drilling, production, processing, power generation, transportation or storage activities;
limit or prohibit drilling activities on lands located within coastal, wilderness, wetlands, groundwater recharge or endangered species inhabited areas, and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources, and require the dedication of surface acreage for habitat conservation;
establish waste management standards or require remedial measures to limit pollution from former operations, such as pit closure, reclamation and plugging and abandonment of wells or decommissioning of facilities;
impose substantial liabilities for pollution resulting from operations or for preexisting environmental conditions on our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
require notice to stakeholders of proposed and ongoing operations;
impose energy efficiency or renewable energy standards on us or users of our products and require the purchase of allowances to account for our greenhouse gas (“GHG”) emissions if we are unable to reduce our emissions below the California statewide maximum limit on covered GHG emissions;
restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics; and
impose taxes or fees with respect to the foregoing matters.
We believe that maintaining compliance with currently applicable health, safety and environmental laws and regulations is unlikely to have a material adverse impact on our business, financial condition, results of operations or cash flows. However, we cannot guarantee this will always be the case given the historical trend of increasingly stringent laws and regulations. We cannot predict how future laws and regulations, or the reinterpretation of existing laws and regulations, may impact our properties or operations.
Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, and operational interruptions or shutdowns, among other sanctions and liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties. For the year ended December 31, 2022, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2023 or that will otherwise have a material impact on our financial position, results of operations or cash flows.
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Regulation of Climate Change and Greenhouse Gas (GHG) Emissions
The potential threat of climate change due to human behaviors continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our E&P operations are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the U.S. Environmental Protection Agency (“EPA”) has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States and together with the U.S. Department of Transportation (“DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions, such as methane. For example, California, through the California Air Resources Board (“CARB”) has implemented a cap-and-trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented low carbon fuel standard (“LCFS”) and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities.
In addition to the actions described above requiring California to achieve total economy-wide carbon neutrality by 2045, California has separately adopted a law requiring the use of 100% zero-carbon electricity within the state by 2045. Additionally, Governor Newsom requested that the CARB analyze pathways to phase out oil extraction across the state by no later than 2045; however, CARB’s 2022 Final Scoping Plan, the blueprint for the state’s carbon neutrality goals, determined such a phase out was not feasible because of continued projected demand for fossil fuels in the transportation sector notwithstanding significant projected decreases in demand for fossil fuels for such uses by 2045. Notwithstanding this, CARB will continue to assess opportunities for phase down in its next five year scoping plan. The 2022 Final Scoping Plan also outlines a plan to phase out natural gas use in buildings, amongst other carbon emission reduction matters. We cannot predict how these various laws, regulations and orders may ultimately affect our operations. However, these initiatives could result in decreased demand for the oil, natural gas, and NGLs that we produce, or otherwise restrict or prohibit our operations altogether in California, and therefore adversely affect our revenues and results of operations.
At the international level, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had withdrawn from the Paris Agreement, President Biden signed an executive order on his first day in office recommitting the United States to the agreement. In February 2021, the United States formally rejoined the Paris Agreement, and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at the 26th Conference of the Parties (“COP26”) in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced in conjunction with the European Union and other partner countries that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity gas. Although no firm commitment or timeline to phase out or phase down all
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fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon our operations.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change-related pledges made by certain candidates for public office. These have included promises to pursue actions to limit emissions and curtail the production of oil and gas, such as banning new leases for production of minerals on federal properties. On January 20, 2021, President Biden issued an executive order calling for increased regulation of methane emissions from the oil and gas sector; for more information, see our regulatory disclosure titled “Air Emissions”. Subsequently, on January 27, 2021, President Biden issued an executive order that called for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across agencies and economic sectors. Other actions that could be pursued by President Biden may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as other GHG emissions limitations for oil and gas facilities.
Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but withheld material information from their investors or customers by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and in September 2022, the Federal Reserve announced that six of the largest banks in the U.S. will participate in a pilot climate scenario analysis to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve began its pilot exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or E&P activities. Additionally, in March 2022, the Securities and Exchange Commission (“SEC”) released a proposed rule that would establish a framework for the reporting of climate risks, targets, and metrics. A final rule is expected to be released in Q2 2023, but we cannot predict the final form and substance of the rule and its requirements. The ultimate impact of the rule on our business is uncertain and, upon finalization may result in additional costs to comply with any such disclosure requirements alongside increased costs of and restrictions on access to capital.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers such as ourselves or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner.
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Moreover, climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
For more information, please see “Item 1A. Risk Factors—Risks Related to Our Operations and IndustryOur business is highly regulated and governmental authorities can delay or deny permits and approvals or change the requirements governing our operations, including the permitting approval process for oil and gas exploration, extraction, operations and production activities, well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy and plans” and “—Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas E&P activities, and reduce demand for the oil and natural gas we produce.”
Human Capital Resources
As of December 31, 2022, we had 1,372 employees, all of whom are located in the United States. Of those, 889 employees are employed in our C&J Well Services business and the remainder are corporate or employed in our E&P business. Currently, none of our employees are covered under collective bargaining or union agreements. We also utilize the service of many third-party contractors throughout our operations.
We believe that developing the best talent, promoting a safe and healthy workplace, providing an inclusive culture, and supporting the well-being of our employees and local communities are critical to the Company's success. The Compensation Committee of the Board has oversight responsibilities for the Company’s human capital management policies, processes and practices, including those related to workforce diversity, pay equity and compensation and incentive structures, employee recruitment, retention and development, and succession planning.
Culture, Core Values and Employee Engagement
We are committed to the well-being of our employees and strive to foster a corporate culture that is reflective of our core values. We provide development opportunities and financial rewards so that our employees are engaged and focused on providing safe, affordable and reliable energy for the people of California.
We believe that fair and equitable pay is an essential element of any successful organization and we reward our talented employees for their hard work, qualities, experience and passion. We offer comprehensive and competitive benefits that support the health and well-being of our employees and their families, while consistently offering opportunities for professional growth and development in line with our mission. In addition, the incentive compensation program for our entire workforce, including our executive team, is tied to company performance on safety and environmental responsibility, as well as financial stewardship.
We proactively work to make sure all employees are fully engaged and empowered to achieve their potential and we are committed to attracting, developing and retaining a highly qualified, diverse and value-focused work force. Our engagement approach centers on transparency and accountability and we use a variety of channels to facilitate open, direct and honest communication, including open forums with executives through periodic town hall meetings and continuous opportunities for discussion and feedback between employees and managers, including performance conversations and reviews. We also survey our employees periodically to assess engagement levels and satisfaction drivers; the results of the engagement surveys are reviewed by senior management and the Board.
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We promote a workplace culture of inclusiveness, dignity and respect for all employees as well as a safe, appropriate, and productive work environment. Accordingly, we prohibit unlawful harassment and discrimination at our work facilities, as well as off-site, including business trips, business functions, and company-sponsored events. In particular, our Code of Conduct prohibits any form of degrading, offensive, or intimidating conduct based on a person’s race, color, ethnicity, national origin, ancestry, citizenship status, sex, gender identity and/or expression, sexual orientation, mental disability, physical disability, medical condition, neurotypicality, physical appearance, genetic information, age, parental status or pregnancy, marital status, religion, creed, political affiliation, military or veteran status, socioeconomic status or background, and any other characteristic protected by law.
Berry is similarly dedicated to this policy with respect to recruitment, hiring, placement, promotion, transfer, training, compensation, benefits, employee activities and general treatment during employment. Our goal is to reflect the broad spectrum of cultural, demographic, and philosophical differences of the communities where we operate, and foster a culture that supports and protects diversity. As a result of our efforts, we have attracted and retained highly talented and experienced women to our workforce in positions across our organization. Currently, our Board is approximately 33% women, our executive leadership team is 25% women, and Berry’s total workforce is approximately 9% women, with the E&P segment being approximately 19% women and CJWS being approximately 5% women.
Safe and Healthy Workplace
We promote a safety-first culture. Health and safety considerations are an integral part of our day-to-day operations and incorporated into the decision-making process for our Board, management and all employees. Meeting meaningful HSE organizational metrics, including with respect to health and safety and spill prevention, is a part of our incentive programs for our entire workforce.
Corporate Information
Our principal executive office is located at 16000 N. Dallas Pkwy, Ste. 500, Dallas, Texas 75248 and our telephone number at that address is (214) 453-2920. Our web address is www.bry.com. We make certain filings with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website as soon as reasonably practicable after they are filed with the SEC. In addition to reports filed or furnished with the SEC, we publicly disclose material information from time to time in press releases, at annual meetings of shareholders, in publicly accessible conferences and investor presentations, and through our website. Information contained in or accessible through our website is not, and should not be deemed to be, part of this report.
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Item 1A. Risk Factors
If any of the following risks actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only risks and uncertainties we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may ultimately materially affect our business.
Summary Risk Factors
The exploration, development and production of oil and natural gas involve highly regulated, high-risk activities with many uncertainties and contingencies that could adversely affect our business, financial condition, results of operations and cash flows. The risks and uncertainties described below are among the items we have identified that could materially adversely affect our business, financial condition, results of operations and cash flows. Before you invest in our common stock, you should carefully consider the risk factors referenced below and as more fully described in “Item 1A. Risk Factors” in this Annual Report.
Risks Related to Our Operations and Industry
There are significant uncertainties with respect to obtaining permits for oil and gas activities in Kern County, where all of our California operations are located, which could impact our financial condition and results of operations.
Attempts by the California state government to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels within the states where we operate.
Our ability to be profitable and maintain our financial condition is highly dependent on commodity prices.
The conflict in Ukraine, related price volatility and geopolitical instability could negatively impact our business.
The marketability of our production is dependent upon the availability of transportation and storage facilities, most of which we do not control.
Our proved reserves and related future net cash flows may prove to be lower than estimated.
Unless we replace oil and natural gas reserves, our future reserves and production will decline.
Drilling for and producing oil and natural gas involves many uncertainties.
We may not drill our identified sites at the times we scheduled or at all.
Competition in the oil and natural gas industry is intense.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets or enter into attractive joint ventures.
We are dependent on our cogeneration facilities to produce steam for our operations. Operational issues and inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise could restrict access to commodity markets.
Most of our operations are in California, much of which is conducted in areas that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.
We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events.
We may be involved in legal proceedings that could result in substantial liabilities.
The loss of senior management or technical personnel could adversely affect operations.
Information technology failures and cyberattacks could affect us significantly.
Increasing attention to ESG matters may impact our operations and our business.
We are subject to economic downturns and effects of public health events, such as the COVID-19 pandemic.
Risks Related to Our Financial Condition
We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our cash flows.
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Our business requires continual capital expenditures that we may be unable to fund.
Inflation could adversely impact our ability to control our costs.
Our hedging activities limit our ability to realize the full benefits of increases in commodity prices and may not fully protect us against the price decreases.
Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities and our lenders could reduce capital available to us for investment.
We may not be able to generate sufficient cash to service our indebtedness.
Declines in commodity prices, changes in expected capital development, increases in operating costs or adverse changes in well performance may result in write-downs of the carrying amounts of our assets.
We have significant concentrations of credit risk with our customers.
Risks Related to Regulatory Matters
Our business is highly regulated and governmental authorities can delay or deny required permits and approvals, or change the requirements governing our operations.
Potential future legislation may generally affect the taxation of natural gas and oil exploration and development companies and may adversely affect our operations and cash flows.
Derivatives legislation and regulations could have an adverse effect on our ability to use derivative instruments to reduce the risks associated with our business.
Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas E&P activities, and reduce demand for the oil and natural gas we produce.
The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations.
Risks Related to our Capital Stock
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
Our significant stockholders and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in the Certificate of Incorporation could enable our significant stockholders to benefit from corporate opportunities that might otherwise be available to us.
Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
The excise tax on repurchases of corporate stock included in the Inflation Reduction Act of 2022 could increase our tax burden and influence our share repurchase decisions.
The payment of dividends will be at the discretion of our board of directors.
We may issue preferred stock, the terms of which could adversely affect the voting power or value of our common stock.
We are an “emerging growth company,” and are able to take advantage of reduced disclosure requirements. Due to losing emerging growth company status in 2023, we expect to incur additional costs.
Our internal control over financial reporting is not currently required to meet all of the standards of Section 404 of the Sarbanes-Oxley Act.
Certain provisions of our Certificate of Incorporation and Bylaws may make it difficult for stockholders to change the composition of our board of directors and may discourage, delay or prevent a merger or acquisition.
Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders.
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Risks Related to Our Operations and Industry
The risks and uncertainties described below are among the items we have identified that could materially adversely affect our business, production, strategy, growth plans, acquisitions, hedging, reserves quantities or value, operating or capital costs, financial condition, results of operations, liquidity, cash flows, our ability to meet our capital expenditure plans and other obligations and financial commitments, and our plans to return capital.
There are significant uncertainties with respect to obtaining permits for oil and gas activities in Kern County, where all of our California operations are located, which could impact our financial condition and results of operations.
The timeline for obtaining permits for our operations in California, including from CalGEM, is and from time to time has been subject to significant delays and uncertainties, and we can provide no assurance that we will always be able to successfully navigate these risks and timely obtain permits or obtain them on favorable terms. In addition, third parties, including individual citizens and non-governmental organizations, may challenge or appeal any permits we receive, leading to further delays. Our oil and gas operations in California are subject to compliance with the California Environmental Quality Act (CEQA), and we cannot receive certain permits and other approval for our operations until a demonstration of compliance with CEQA has been made. There have been a number of developments at both the California state and local level that have resulted in delays in the issuance of permits for oil and gas activities in Kern County, as well as a more time- and cost- intensive permitting process. As a result of ongoing regulatory uncertainty in California, our capital program for 2023 has been prepared based on the assumption that no permits for new wells will be issued under the Kern County EIR in 2023. If we are unable to timely receive the permits and other approvals needed for our future plans, our financial condition, results of operations and prospects could be adversely and materially impacted.
In Kern County, where all of our California assets are located, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (an “EIR”) covering oil and gas operations in Kern County (the “Kern County EIR”). In 2020, a lawsuit was filed challenging the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County made certain revisions to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County prepared a supplemental EIR (the “Supplemental EIR”) which was approved by the Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs, a Kern County Superior Court judge suspended use of the Supplemental EIR in October 2021 pending further review by the Court. In June 2022, the Kern County Superior Court ruled in favor of Kern County in part but also found that the Supplemental EIR still failed to meet the minimum requirements of CEQA. In August 2022, the Kern County Board of Supervisors approved changes which addressed four discrete issues identified by the court in its June 2022 ruling. The Kern County Superior Court subsequently issued a ruling in October 2022 determining that the Kern County Supplemental EIR was not decertified, but ordered Kern County to address the four discrete issues previously identified before the Supplemental EIR could become effective. Kern County then filed notice with the court of the changes and on November 2, 2022, the trial court lifted the order preventing reliance on the Supplemental EIR. In December 2022, the Kern County Superior Court denied a motion to stay this action and the plaintiffs appealed. On January 26, 2023, the California Fifth District Court of Appeal issued a preliminary order reinstating the suspension of the Supplemental EIR to meet CEQA requirements pending the outcome of a final order on Kern County’s ability to rely on the Supplemental EIR during the appeals process. While the court has not issued a final order to date, it is possible that use of the Supplemental EIR will remain suspended through the duration of the appeals process, which would result in significant ongoing disruption to the permitting process in Kern County for an extended period of time. Furthermore, if the Supplemental EIR is ultimately determined to be deficient upon resolution of the appeals process, use of the Supplemental EIR to satisfy CEQA requirements for drilling permits may be suspended until such deficiencies are resolved, which could extend such disruptions for the foreseeable future. In addition, CalGEM provided notice to operators on February 2, 2023 that, in light of the preliminary order, it would no longer recognize job cards issued by Kern County as CEQA lead agency in reliance on the Supplemental EIR between November 2, 2022 and January 26, 2023 (the “CalGEM Notice”). We were issued a number of job cards from Kern County during this period that we expected would be available for our drilling program in 2023. Even if the California Fifth District Court of
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Appeal lifts the suspension on reliance on the Supplemental EIR, there is no assurance that we will be able to use those previously-issued permits or how quickly any new permits may be issued by CalGEM. For additional information, see “Regulatory Matters – California Permitting Considerations.”
Separately, in February 2021, the Center for Biological Diversity filed suit against CalGEM alleging that its reliance on the Kern County EIR for oil and gas decisions violates CEQA, and that an independent environmental impact review in compliance with CEQA is required by CalGEM before the agency can issue oil and gas permits and approvals. Most recently, the Alameda County Superior Court denied CalGEM’s motion for judgment on the pleadings and the lawsuit remains ongoing. We cannot predict its ultimate outcome or whether it could result in changes to the requirements for demonstrating compliance with CEQA and the permitting process, even if the Supplemental EIR is ultimately deemed sufficient and reinstated. The potential impact of this and potentially future litigation contributes to the uncertainty with respect to our ability to timely obtain the permits and approvals needed to conduct our operations.
If we are unable to obtain the required permits and approvals needed to conduct our operations on a timely basis or at all our financial condition, results of operations and prospects could be adversely and materially impacted. At this time we expect that greater than 90% of our planned 2023 production will come from our base production, with the remainder from workovers and other activities related to existing wellbores, as well as from a limited number of new wells drilled during the year for which we already have permits. As a result of the CalGEM Notice and the Kern County EIR legal challenges, our current capital budget for 2023 has been prepared on the assumption that no permits for new wells will be issued in the area covered by the Kern County EIR in 2023. Furthermore, if we are unable to obtain new well drill permits through the Supplemental EIR or other avenues for CEQA compliance through 2024, we expect there to be a material impact on our 2024 capital plan and certain of our proved undeveloped reserves will expire at the end of 2024. Based on our reserves as of December 31, 2022, if we are unable to obtain permits for new wells through 2024, it will likely result in the loss of some amount of the proved undeveloped reserves expiring at the end of 2024. In addition, any changes to the CEQA compliance requirements or the other conditions and requirements for permit issuance or renewal, including the imposition of new or more stringent environmental reviews or stricter operational or monitoring requirements, or a prohibition on the issuance of new permits for oil and has activities in Kern County or California as a whole, would have an adverse and material effect on our financial condition, results of operations and prospects. For additional information, see “Items 1 and 2. Business and Properties—Regulation of Health, Safety and Environmental Matters”.
Attempts by the California state government to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels within the states where we operate.
California, where most of our operations and assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations. Federal, state and local laws and regulations govern most aspects of E&P in California. Collectively, the effect of the existing laws and regulations is to potentially limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, and reduce the amount of oil and natural gas that we can produce from our wells below levels that would otherwise be possible. Additionally, the regulatory burden on the industry increases our costs and consequently may have an adverse effect upon operations, capital expenditures, earnings and our competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns, reputational damage 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.
Additionally, the California state government recently has taken several actions that could adversely impact future oil and gas production and other activities in the state. For example:
In November 2019, the State Department of Conservation issued a press release announcing three actions by CalGEM: (1) a moratorium on approval of new high–pressure cyclic steam wells pending a study of the practice to address surface expressions experienced by certain operators; (2) a review and
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update of regulations regarding public health and safety near oil and natural gas operations pursuant to additional duties assigned to CalGEM by the California State Legislature in 2019 (discussed above); (3) a performance audit of CalGEM's permitting processes for issuing WST permits and PALs for underground injection activities by the State Department of Finance; and (4) an independent review of the technical content of pending WST and PAL applications by Lawrence Livermore National Laboratory. In January 2020, CalGEM issued a formal notice to operators, including us, that they had issued restrictions imposing the previously announced moratorium to prohibit new underground oil-extraction wells from using high-pressure cyclic steaming process. The moratorium on permitting for new high–pressure cyclic steam wells and restrictions on WST remains in effect.
In October 2020, the California Governor issued an executive order that established a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directed state agencies to implement other measures to mitigate climate change and strengthen biodiversity. At this time, we cannot predict the potential future actions that may result from this order or how such may potentially impact our operations.
In September 2022, the California Governor signed Senate Bill No. 1279 into law, codifying an executive order previously issued by the Governor’s Office requiring the state to achieve carbon neutrality by 2045. In addition, Governor Newsom previously issued an executive order that established several goals and directed several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: (1) phasing out the sale of vehicles with internal combustion engines; (2) developing strategies for the closure and repurposing of oil and gas facilities in California; and (3) calling on the California State Legislature to enact new laws prohibiting hydraulic fracturing in the state by 2024.
In September 2022, the California Governor signed into law Senate Bill No. 1137 which prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks effective January 1, 2023. On January 6, 2023, CalGEM’s emergency regulations to support implementation of Senate Bill No. 1137 were approved by the Office of Administrative Law and final regulations were published. The regulations include applicable requirements of notice to property owners and tenants regarding the work performed and offering the sampling of test water wells or surface water before and after drilling; the contents of required notices for new production facilities; the annual submission of a sensitive receptor inventory and sensitive receptor map and the contents and format of the same; and the requirements of statements where operators have determined a location not to be within a health protection zone. Additional provisions of Senate Bill No. 1137 would also require pollution controls for existing wells and facilities within the same 3,200-foot setback area. Senate Bill No. 1137 is currently stayed pending a vote of the California General Election in November 2024. However, the stay could be delayed if there are legal challenges to the Secretary of State’s certification. We continue to assess the impacts of Senate Bill No. 1137 and CalGEM’s regulations, but we currently estimate that approximately 13% of our overall proved reserves are within the setbacks established by Senate Bill No. 1137. We do not expect this law to result in any material change in our overall existing proved developed producing reserves or current production rates.
The clear trend in California is to impose increasingly stringent restrictions on oil and natural gas activities. We cannot predict what actions the Governor of California, the Legislature, or state agencies may take in the future, but we could face increased compliance costs, delays in obtaining the approvals necessary for our operations, exposure to increased liability, or other limitations as a result of future actions by these parties. Moreover, new developments resulting from the current and future actions of these parties could also materially and adversely affect our ability to operate, successfully execute drilling plans, or otherwise develop our reserves. Accordingly, recent and future actions by the Governor of California, the Legislature, and state agencies could materially and adversely affect our business, results of operations, and financial condition.
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Our ability to operate profitably and maintain our business and financial condition are highly dependent on commodity prices, which historically have been very volatile and are driven by numerous factors beyond our control. If oil prices were to significantly decline for a prolonged period of time, our business, financial condition and results of operations may be materially and adversely affected.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, value of our reserves, access to capital and future rate of growth, among other factors. However, the price we receive for our oil and natural gas production depends on numerous factors beyond our control, including not limited to, the following:
overall domestic and global political and economic conditions, including the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict, including the ongoing conflict in Ukraine, rising inflation levels and government efforts to reduce inflation, or a prolonged recession;
changes in global supply and demand for oil and natural gas, including changes in demand resulting from general and specific economic conditions relating to the business cycle and other factors;
the actions of OPEC and/or OPEC+;
the price and quantity of imports of foreign oil and natural gas;
the level of global oil and natural gas E&P activity
the level of global oil and natural gas inventories;
weather conditions;
domestic and foreign governmental legislative efforts, executive actions and regulations, including environmental regulations, climate change regulations and taxation;
the effect of energy conservation efforts;
stockholder activism or activities by non-governmental organizations to limit certain sources of capital for the energy sector or restrict the exploration, development and production of oil and gas;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
Historically, the markets for oil and natural gas have been extremely volatile and will likely continue to be volatile in the future. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Global economic growth drives demand for energy from all sources, including fossil fuels. When the U.S. and global economies experience weakness, demand for energy will decline with accompanying declines in commodity prices; similarly, when growth in global energy production outstrips demand, the excess supply results in commodity price declines.
Concerns over global economic conditions, energy costs, geopolitical issues, such as the ongoing conflict in Ukraine, the impacts of the COVID-19 pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have in the past contributed to significantly reduced economic activity and diminished expectations for the global economy. If the economic climate in the United States or abroad were deteriorate, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect our level of operations and ultimately materially adversely impact our results of operations, financial condition and free cash flow.
Additionally, although the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. Refer to Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Environment and Market Conditions”.
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Past declines in pricing, and any declines that may occur in the future, can be expected to adversely affect our business, financial condition and results of operations. Such declines adversely affect well and reserve economics and may reduce the amount of oil and natural gas that we can produce economically, resulting in deferral or cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve sufficiently to support such operations. Any extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
The conflict in Ukraine and related price volatility and geopolitical instability could negatively impact our business.
In late February 2022, Russia launched significant military action against Ukraine. The conflict has caused, and could intensify, volatility in the prices of natural gas, oil and NGLs, and the extent and duration of the military action, sanctions and resulting market disruptions have been significant and could continue to have a substantial impact on the global economy and our business for an unknown period of time. There is evidence that the increase in crude oil prices during the first half of calendar year 2022 was partially due to the impact of the conflict between Russia and Ukraine on the global commodity and financial markets, and in response to economic and trade sanctions that certain countries have imposed on Russia. Alternatively, a cessation of the hostilities between Russia and Ukraine as a result of a negotiated withdrawal or otherwise could cause commodity prices to decline, which would reduce the revenues we receive for our oil and gas production. Any such volatility and disruptions may also magnify the impact of the other risks described in this “Risk Factors” section.
The marketability of our production is dependent upon transportation and storage facilities and other facilities, most of which we do not control, and the availability of such transportation and storage capabilities. If we are unable to access such facilities on commercially reasonable terms, our operations would likely be interrupted, our production could be curtailed, and our revenues reduced, among other adverse consequences.
The marketing of oil, natural gas and NGLs production depends in large part on the availability, proximity and capacity of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. Storage and transportation capacity for our production is limited and may become unavailable on commercially reasonable terms or at all. For example, storage and transportation capacity became scarce during the second quarter of 2020 due to the unprecedented dual impact of a severe global oil demand decline coupled with a substantial increase in supply. As traditional tanks filled, large quantities of oil were being stored in offshore tankers around the world, including off the coast of California. Where storage was available, such as offshore tankers, storage costs increased sharply. The potential risk remains that storage for oil may be unavailable and our existing capacity may be insufficient to support planned production rates in the event of another deterioration in demand or a supply surge or both.
Moreover, if the imbalance between supply and demand and the related shortage of storage capacity worsen, the prices we receive for our production could deteriorate and could potentially even become negative. Additionally, if we were unable to obtain the needed storage capacity, we could be forced to shut-in a significant amount of our California production, which could have a material adverse effect on our financial condition, liquidity and operational results. If we are forced to shut in production, we would incur additional costs to bring the associated wells back online. While production is shut in, we would likely incur additional costs and operating expenses to, among other things, maintain the health of the reservoirs, meet contractual obligations and protect our interests, without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we have also shut in steam injection for the associated reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could be decreased and there could be potential additional impairments and associated charges to our earnings. A reduction in our reserves could also result in a reduction to our borrowing base under the 2021 RBL Facility and our liquidity. The ultimate significance of the impact of any production disruptions, including the extent of the adverse impact on our financial and operational results, will be dictated by the length of
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time that such disruptions continue, which will in turn depend on how long storage remains filled and unavailable to us, which is largely unpredictable and based on factors outside of our control.
In addition to the constraints we may face due to storage capacity shortages, the volume of oil and natural gas that we can produce is subject to limitations resulting from pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, and physical damage to the gathering, transportation, storage, processing, fractionation, refining or export facilities that we utilize. The curtailments arising from these and similar circumstances may last from a few days to several months or longer and, in many cases, we may be provided only limited, if any, advance notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or any inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.
Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.
Estimation of reserves and related future net cash flows is a partially subjective process of estimating accumulations of oil and natural gas that includes many uncertainties. Our estimates are based on various assumptions, which may ultimately prove to be inaccurate, including:
the similarity of reservoir performance in other areas to expected performance from our assets;
the quality, quantity and interpretation of available relevant data;
commodity prices;
production, operating costs, taxes and costs related to GHG regulations;
development costs;
the effects of government regulations, including our ability to obtain permits in a timely manner, or at all, for proved undeveloped reserves; and 
future workover and asset retirement costs.
Misunderstanding these variables, inaccurate assumptions, changed circumstances or new information could require us to make significant negative reserves revisions.
We currently expect improved recovery, extensions and discoveries and, potentially acquisitions, to be our main sources for reserves additions. However, factors such as the availability of capital, geology, government regulations and our ability to obtain permits, the effectiveness of development plans and other factors could affect the source or quantity of future reserves additions. Any material inaccuracies in our reserves estimates could materially affect the net present value of our reserves, which could adversely affect our borrowing base and liquidity under the 2021 RBL Facility, as well as our results of operations.
Unless we replace oil and natural gas reserves, our future reserves and production will decline.
Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Success requires us to deploy sufficient capital to projects that are geologically and economically attractive which is subject to the capital, development, operating and regulatory risks already discussed above under the heading “—Our business requires continual capital expenditures. We may be unable to fund these investments through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or production. Our capital program is also susceptible to risks, including regulatory and permitting risks, that could materially affect its implementation.” The Company reduced its planned capital expenditures in 2020 in response to the effects of COVID-19 and the actions of OPEC+, which negatively impacted production during 2020. While we subsequently increased our planned capital expenditures for 2021, it is possible that lower-than-expected demand and prices for commodities in the future could materially and adversely affect our future planned capital
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expenditures. Furthermore, beginning in the second quarter of 2022, we adjusted our 2022 capital development program due to the delays in permit issuance and insufficient permit inventory. As a result of ongoing regulatory uncertainty in California, our 2023 capital program has been prepared based on the assumption that no permits for new wells will be issued under the Kern County EIR in 2023. If we are unable to obtain new well drill permits through 2024, it will likely result in the loss of some amount of the proved undeveloped reserves expiring at the end of 2024.
Over the long term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.
Drilling for and producing oil and natural gas involves many uncertainties that could adversely affect our results.
The success of our development, production and acquisition activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable production or may result in a downward revision of our estimated proved reserves due to:
•    poor production response;
•    ineffective application of recovery techniques;
•    increased costs of drilling, completing, stimulating, equipping, operating, maintaining and abandoning wells;
•    delays or cost overruns caused by equipment failures, accidents, environmental hazards, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes and other matters; and
•    misinterpretation of geophysical and geological analyses, production data and engineering studies.
Additional factors may delay or cancel our operations, including:
•    delays due to regulatory requirements and procedures, including unavailability or other restrictions limiting permits and limitations on water disposal, emission of GHGs, steam injection and well stimulation, such as California’s recent limitations on cyclic steaming above the fracture gradient;
•    pressure or irregularities in geological formations;
•    shortages of or delays in obtaining equipment, qualified personnel or supplies including water for steam used in production or pressure maintenance;
•    delays in access to production or pipeline transmission facilities; and
power outages imposed by utilities which provide a portion of our electricity needs in order to avoid fire hazards and inspect lines in connection with seasonal strong winds, which have begun to occur recently and may impact our operations.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to property, reserves and equipment, pollution, environmental contamination and regulatory penalties.
We may not drill our identified sites at the times we scheduled or at all.
We have specifically identified locations for drilling over the next several years, which represent a significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. Legislative and regulatory developments, such as California’s recently adopted setback rules, could prevent us from planned drilling activities. Additionally, as discussed under “—Risks Related to Regulatory Matters,” new regulations and legislative activity could result in a significant delay or decline in, and/or the incurrence of additional costs for, the approval of the permits required to develop our properties in accordance with our plans. If future drilling results in these projects do not establish sufficient reserves to achieve an economic
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return, we may curtail drilling or development of these projects. Accordingly, we cannot guarantee that these prospective drilling locations or any other drilling locations we have identified will ever be drilled or if we will be able to economically produce oil or natural gas from these drilling locations. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring in the next three years represented approximately 3% of our total net acreage at December 31, 2022.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.
Our future success will depend on our ability to evaluate, select and acquire suitable properties, market our production and secure skilled personnel to operate our assets in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ greater financial, technical and personnel resources than we do.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets or enter into attractive joint ventures, and any inability to do so may disrupt our business and hinder our ability to grow.
There is no guarantee we will be able to identify or complete attractive acquisitions. Our capital expenditure budget for 2023 does not allocate any amounts for acquisitions of oil and natural gas properties. If we make acquisitions, we would need to use cash flows or seek additional capital, both of which are subject to uncertainties discussed in this section. Competition may also increase the cost of, or cause us to refrain from, completing acquisitions. Our debt arrangements impose certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness. See “—Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.” In addition, the success of completed acquisitions will depend on our ability to integrate effectively the acquired business into our existing operations, may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.
We are dependent on our cogeneration facilities to produce steam for our operations. Contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.
We are dependent on four cogeneration facilities that, combined, provide approximately 16% of our steam capacity and approximately 55% of our field electricity needs in California at a discount to market rates. To further offset our costs, we sell surplus power to California utility companies produced by certain of our cogeneration facilities under long-term contracts. Should we lose, be unable to renew on favorable terms, or be unable to replace such contracts, we may be unable to realize the cost offset currently received. Our ability to benefit from these facilities is also affected by our ability to consistently generate surplus electricity and fluctuations in commodity prices. For example, during 2021 electricity sales increased by $10 million, or 38%, due to higher unit sales during the summer when we receive peak pricing, and higher year–over–year gas pricing. Furthermore, market fluctuations in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration facilities and any corresponding increase in the price of steam could significantly impact our operating costs. If we were unable to find new or replacement steam sources, lose existing sources or experience installation delays, we may be unable to maximize production from our heavy oil assets. If we were to lose our electricity sources, we would be subject to the electricity rates we could negotiate. For a more detailed discussion of our electricity sales contracts, see “Items 1 and 2. Business and Properties—Operational Overview—Electricity.”
Our producing properties are located primarily in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.
We operate primarily in California, which is one of the most heavily regulated states in the United States with respect to oil and gas operations. This geographic concentration disproportionately affects the success and profitability of our operations exposing us to local price fluctuations, changes in state or regional laws and regulations, political risks, limited acquisition opportunities where we have the most operating experience and
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infrastructure, limited storage options, drought conditions, and other regional supply and demand factors, including gathering, pipeline and transportation capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. We discuss such specific risks to our California operations in more detail elsewhere in this section.
Most of our operations are in California, much of which is conducted in areas that may be at risk of damage from fire, mudslides, earthquakes, floods or other natural disasters or extreme weather events.
We currently conduct operations in California near known wildfire and mudslide areas and earthquake fault zones. A future natural disaster, or extreme weather event, such as a fire, mudslide, flood, drought or an earthquake, could cause substantial interruption and delays in our operations, damage or destroy equipment, prevent or delay transport of our products and cause us to incur additional expenses, which would adversely affect our business, financial condition and results of operations. In addition, our facilities would be difficult to replace and would require substantial lead time to repair or replace. For example, in December of 2022, severe winter storms caused operational challenges, production downtime, and much higher natural gas prices in California. Extreme, adverse weather conditions, including flooding, have continued in the first quarter of 2023 and impacted our operations and production levels. These events could occur with greater frequency as a result of the potential impacts from climate change. The insurance we maintain against earthquakes, mudslides, fires, floods and other natural disasters would not be adequate to cover a total loss of our facilities, may not be adequate to cover our losses in any particular case and may not continue to be available to us on acceptable terms, or at all.
Operational issues and inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise could restrict access to markets for the commodities we produce.
Our ability to market our production of oil, gas and NGLs depends on a number of factors, including the proximity of production fields to pipelines, refineries and terminal facilities, competition for capacity on such facilities, damage, shutdowns and turnarounds at such facilities and their ability to gather, transport or process our production. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely, and expect to rely in the future, on third-party facilities for services such as storage, processing and transmission of our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. If our access to markets for commodities we produce is restricted, our costs could increase and our expected production growth may be impaired.
We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not fully insured against all risks. Our oil and natural gas E&P activities, are subject to risks such as fires, explosions, oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment, equipment failures and industrial accidents. We are exposed to similar risks indirectly through our customers and other market participants such as refiners. Other catastrophic events such as earthquakes, floods, mudslides, fires, droughts, contagious diseases, terrorist attacks and other events that cause operations to cease or be curtailed may adversely affect our business and the communities in which we operate. For example, utilities have begun to suspend electric services to avoid wildfires during windy periods in California, a business disruption risk that is not insured. We may be unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented.
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and
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their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of the attention of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change materially from one period to the next.
The loss of senior management or technical personnel, or our inability to successfully adapt to the new executive leadership team, could adversely affect our results and operations.
We depend on, and could be deprived of, the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of services of any of these individuals.
In November 2022, we announced a significant change to our management team, including effective January 1, 2023, the Chief Executive Officer transitioning to the role of Executive Chair, the Chief Financial Officer temporarily retaining his role as member of the Board and serving as strategic advisor to the new management team (to terminate March 4, 2023), and the promotion of a new Chief Executive Officer (our former Chief Operating Officer, which position was eliminated), President (our former General Counsel and Corporate Secretary), Chief Financial Officer (our Chief Accounting Officer, which position he also has maintained) and General Counsel and Corporate Secretary (our former Associate General Counsel). Although the newly appointed executive team has extensive experience with the Company and our industry, this leadership transition may result in changes to our management style, operations and strategies. Any significant leadership change or senior management transition involves inherent risk and any failure to ensure a smooth transition could hinder our strategic planning, business execution and future performance. In particular, this or any future leadership transition may result in a loss of personnel with deep institutional or technical knowledge and changes in business strategy or objectives, and has the potential to disrupt our operations and relationships with employees and customers due to added costs, operational inefficiencies, changes in strategy, decreased employee morale and productivity and increased turnover. Failure to successfully transition to the new leadership team could affect our ability to attract and retain skilled personnel and could have an adverse effect on our results of operations, business and financial position.
Information technology and operational failures and cyberattacks could affect us significantly.
We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. User access and security of our sites and systems are critical elements of our operations, as are cloud security and protection against cybersecurity incidents. Without accurate data from and access to these systems and networks, our ability to communicate and control and manage our business could be adversely affected.
We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. We have experienced cybersecurity incidents but have not suffered any material adverse impacts to our business and operations as a result of such incidents. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations, misdirected wire transfers, or other adverse events. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability, including regulatory enforcement, violation of privacy or securities laws and regulations, and individual or class action claims.
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The energy industry has become increasingly dependent on digital technologies to conduct day-to-day operations, and the use of mobile communication devices has rapidly increased. Industrial control systems such as supervisory control and data acquisition (“SCADA”) systems now control large-scale processes that can include multiple sites across long distances. The Company’s technologies, systems, networks, including its SCADA system, and those of its business partners may become the target of cyber-attacks or security breaches.
Increasing attention to environmental, social and governance (ESG) matters may impact our business.
Increasing attention to, and social expectations on companies to address, climate change and other environmental and social impacts, investor and societal explanations regarding voluntary ESG disclosures, and increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the near future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, or that, notwithstanding our reliance on any reputable third party registries, that the offsets we do purchase will successfully achieve the emissions reductions they represent. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations.
Public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e. misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and
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governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further ESG-related focus and scrutiny.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
We are subject to economic downturns and the effects of public health events, such as the COVID-19 pandemic, which may materially and adversely affect the demand and the market price for our products.
The COVID-19 pandemic has adversely affected the global economy, and has resulted in, among other things, travel restrictions, business closures and the institution of quarantining and other mandated and self-imposed restrictions on movement. The severity, magnitude and duration of COVID-19 or another pandemic, the extent of actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could force us to reduce costs, including by decreasing operating expenses and lowering capital expenditures, and such actions could negatively affect future production and our reserves. We may experience labor shortages if our employees are unwilling or unable to come to work because of illness, quarantines, government actions or other restrictions in connection with the pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may need to suspend operations. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile. We cannot predict the duration and extent of the pandemic's adverse impact on our operating results.
Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global business and economic environment adversely affects our business and financial results, it may also have the effect of heightening or exacerbating many of the other risks described in the “Risk Factors” herein.
Risks Related to Our Financial Condition
We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our cash flows.
We currently have substantial U.S. federal and state net operating loss (“NOL”) carryforwards and U.S. federal general business credits. Our ability to use these tax attributes to reduce our future U.S. federal and state income tax obligations depends on many factors, including our future taxable income, which cannot be assured. In addition, our ability to use NOL carryforwards and other tax attributes may be subject to significant limitations under Section 382 and Section 383 of the Internal Revenue Code of 1986, as amended (the “Code”). Under those sections of the Code, if a corporation undergoes an “ownership change” (as defined in Section 382 of the Code), the corporation’s ability to use its pre-change NOL carryforwards and other tax attributes may be substantially limited.
Determining the limitations under Section 382 of the Code is technical and highly complex. A corporation generally will experience an ownership change if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. We may in the future undergo an ownership change under Section 382 of the Code. If an ownership change occurs, our ability to use our NOL carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations may be materially limited, which could adversely affect our cash flows.
Our business requires continual capital expenditures. We may be unable to fund these investments through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a
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decline in our oil and natural gas reserves or production. Our capital program is also susceptible to risks, including regulatory and permitting risks, that could materially affect its implementation.
Our industry is capital intensive. We have a 2023 capital expenditure budget of between $95 to $105 million, excluding CJWS capital of approximately $8 million. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of permits, and our ability to obtain them in a timely manner or at all, legal and regulatory processes and other restrictions, and technological and competitive developments. Our current capital program for 2023 focuses on new wells drilled during the year for which we already have permits or have existing CEQA analysis completed, and otherwise focuses on workovers and other activities related to existing wellbores. As a result of ongoing regulatory uncertainty in California, the capital program has been prepared based on the assumption that no permits for new wells will be issued under the Kern County EIR in 2023. In addition, a reduction or sustained decline in commodity prices from current levels may force us to reduce our capital expenditures, which would negatively impact our ability to grow production. Current and future laws and regulations may prevent us from being able to execute our drilling programs and development and optimization projects.
We expect to fund our 2023 capital expenditures with cash flows from our operations, supplemented by cash which was built as excess free cash flow 2022; however, our cash flows from operations, and access to capital should such cash flows and cash prove inadequate, are subject to a number of variables, including:
the volume of hydrocarbons we are able to produce from existing wells and our ability to bring those to market;
the prices at which our production is sold and our operating expenses;
the success of our hedging program;
our proved reserves, including our ability to acquire, locate and produce new reserves;
our ability to borrow under the 2021 RBL Facility;
and our ability to access the capital markets.
If our revenues or the borrowing base under the 2021 RBL Facility decrease as a result of lower oil, natural gas and NGL prices, lack of required permits and other operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital were needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. Any additional debt financing would carry interest costs, diverting capital from our business activities, which in turn could lead to a decline in our reserves and production. If cash flows generated by our operations or available borrowings under the 2021 RBL Facility were not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Inflation could adversely impact our ability to control our costs, including our operating expenses and capital costs.
The U.S. inflation rate has been steadily increasing since 2021 and throughout much of 2022. Such inflationary pressures have resulted from supply chain disruptions caused by the COVID pandemic, increased demand, labor shortages and other factors, including the conflict between Russia and the Ukraine which began in late February 2022. Similar to other companies in our industry, we have experienced inflationary pressures on our operating costs - namely inflationary pressures have resulted in increases to the costs of our goods, services and personnel, which in turn, have caused our capital expenditures and operating costs to rise. Although inflation rates started to stabilize in late 2022 and even decrease from the levels experienced earlier in the year, we are unable to accurately predict if such inflationary pressures and contributing factors will continue into 2023. To the extent elevated inflation remains, we may experience further cost increases for our operations, including natural gas purchases and oilfield services
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and equipment as increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations, as well as increased labor costs. An increase in oil, natural gas and NGL prices may cause the costs of materials and services to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher commodity prices and revenues, would negatively impact our business, financial condition and results of operation.
Our hedging activities limit our ability to realize the full benefits of increases in commodity prices and our potential gains.
We enter into hedges to manage our exposure to price risks in the marketing of our oil and natural gas, mitigate our economic exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. The 2021 RBL Facility requires us to maintain commodity hedges (other than three-way collars) on minimum notional volumes of (i) at least 75% of our reasonably projected production of crude oil from our proved developed producing (“PDP”) reserves, for 24 full calendar months after the effective date of the 2021 RBL Facility and after each May 1 and November 1 of each calendar year (each, a “Minimum Hedging Requirement Date”) and (ii) at least 50% of our reasonably projected production of crude oil from our PDP reserves, for each full calendar month during the period from and including the 25th full calendar month following each such Minimum Hedging Requirement Date through and including the 36th full calendar month following each such Minimum Hedging Requirement Date; provided, that in the case of each of the above clauses (i) and (ii), the notional volumes hedged are deemed reduced by the notional volumes of any short puts or other similar derivatives having the effect of exposing us to commodity price risk below the “floor”. In addition to minimum hedging requirements and other restrictions in respect of hedging described therein, the 2021 RBL Facility contains restrictions on our commodity hedging which prevent us from entering into hedging agreements (i) with a tenor exceeding 48 months or (ii) for notional volumes which (when aggregated with other hedges then in effect other than basis differential swaps on volumes already hedged) exceed, as of the date such hedging agreement is executed, 90% of our reasonably projected production of crude oil from our PDP reserves, for each month following the date such hedging agreement is entered into, provided that the volume limitations above do not apply to short puts or put options contracts that are not related to corresponding calls, collars or swaps.
While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge or expose us to the risk of financial losses depending on commodity price movements and other circumstances. Our ability to realize the benefits of our hedges also depends in part upon the counterparties to these contracts honoring their financial obligations. If any of our counterparties are unable to perform their obligations in the future, we could be exposed to increased cash flow volatility that could affect our liquidity.
We may be unable to, or may choose not to, enter into sufficient fixed-price purchase or other hedging agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam operations economically or at desired levels, and our commodity price risk management activities may prevent us from fully benefiting from price increases and may expose us to other risks.
To develop our heavy oil in California we must economically generate steam using natural gas. We seek to reduce our exposure to the potential unavailability of, pricing increases for, and volatility in pricing of, natural gas by entering into fixed-price purchase agreements and other hedging transactions. We seek to reduce our exposure to potential price increases and volatility in pricing of oil by entering into swaps, calls and other hedging transactions. We may be unable to, or may choose not to, enter into sufficient agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam operations economically or at desired levels.
In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility, which requires us to maintain commodity hedges (other than three-way collars) on minimum notional volumes of (i) at least 75% of our
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reasonably projected production of crude oil from our PDP reserves, for 24 full calendar months after the effective date of the 2021 RBL Facility and after each May 1 and November 1 of each calendar year and (ii) at least 50% of our reasonably projected production of crude oil from our PDP reserves, for each full calendar month during the period from and including the 25th full calendar month following each such Minimum Hedging Requirement Date through and including the 36th full calendar month following each such Minimum Hedging Requirement Date; provided, that in the case of each of the above clauses (i) and (ii), the notional volumes hedged are deemed reduced by the notional volumes of any short puts or other similar derivatives having the effect of exposing us to commodity price risk below the “floor”. In addition to minimum hedging requirements and other restrictions in respect of hedging described therein, the 2021 RBL Facility contains restrictions on our commodity hedging which prevent us from entering into hedging agreements (i) with a tenor exceeding 48 months or (ii) for notional volumes which (when aggregated with other hedges then in effect other than basis differential swaps on volumes already hedged) exceed, as of the date such hedging agreement is executed, 90% of our reasonably projected production of crude oil from our PDP reserves, for each month following the date such hedging agreement is entered into, provided that the volume limitations above do not apply to short puts or put options contracts that are not related to corresponding calls, collars, or swaps.
Our commodity price risk management activities as well as the hedging requirements of the 2021 RBL facility may prevent us from fully benefiting from price increases. Additionally, our hedges are based on major oil and gas indexes, which may not fully reflect the prices we realize locally. Consequently, the price protection we receive may not fully offset local price declines.
As of December 31, 2022, we have hedged gas purchases at the following approximate volumes and prices: 45,800 mmbtu/d at $5.14 per mmbtu in 2023.
Our commodity price risk management activities may also expose us to the risk of financial loss in certain circumstances, including instances in which:
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.
Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities. In addition, the borrowing base under the 2021 RBL Facility is subject to periodic redeterminations and our lenders could reduce capital available to us for investment.
The 2021 RBL Facility, the 2022 ABL Facility and the indenture governing our 2026 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. Failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. These agreements contain covenants, that, among other things, limit our ability to:
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
transfer, sell or dispose of assets;
make investments;
create certain liens securing indebtedness;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
hedge future production or interest rates;
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repay or prepay certain indebtedness prior to the due date;
engage in transactions with affiliates; and
engage in certain other transactions without the prior consent of the lenders.
In addition, the 2021 RBL Facility and the 2022 ABL Facility require us and CJWS, respectively, requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios, which may limit our ability to borrow funds to withstand a future downturn in our business, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of these limitations.
In addition, the 2021 RBL Facility has hedging requirements which may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge or expose us to the risk of financial loss in certain circumstances.
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
The amount available to be borrowed under the 2021 RBL Facility is subject to a borrowing base and will be redetermined semiannually and will depend on the estimated volumes and cash flows of our proved oil and natural gas reserves and other information deemed relevant by the administrative agent of, or two-thirds of the lenders under, the 2021 RBL Facility. We, the administrative agent and lenders, each may request one additional redetermination between each regularly scheduled redetermination. Furthermore, our borrowing base is subject to automatic reductions due to certain asset sales and hedge terminations, the incurrence of certain other debt and other events as provided in the 2021 RBL Facility. For example, the 2021 RBL Facility currently provides that to the extent we incur certain unsecured indebtedness, our borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt that exceeds the amount, if any, of certain other debt that is being refinanced by such unsecured debt. Reduction of our borrowing base under the 2021 RBL Facility could reduce the capital available to us for investment in our business. Additionally, we could be required to repay a portion of the 2021 RBL Facility to the extent that after a redetermination our outstanding borrowings at such time exceed the redetermined borrowing base. The 2022 ABL Facility is also subject to adjustments to the borrowing base.
For additional details regarding the terms of the 2021 RBL Facility, the 2022 ABL Facility and our 2026 Notes, see “Liquidity and Capital Resources”.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
As of December 31, 2022, we had $400 million outstanding on our 2026 Notes and no outstanding borrowings under our 2021 RBL Facility, with approximately $193 million of available borrowings capacity. As of December 31, 2022, CJWS had no borrowings outstanding with $13 million of available borrowing capacity under the 2022 ABL Facility. Our ability to make scheduled payments on or to refinance our debt obligations, including the 2021 RBL Facility, the 2022 ABL Facility and our 2026 Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors that may be beyond our control. If oil and natural gas prices remain at low levels for an extended period of time or further deteriorate, our cash flows from operating activities may be insufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The 2021 RBL Facility, the 2022 ABL Facility and our 2026 Notes currently restrict our ability to dispose of assets and our use of the proceeds from any such disposition. We may not be able to consummate dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.
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Declines in commodity prices, changes in expected capital development, increases in operating costs or adverse changes in well performance may result in write-downs of the carrying amounts of our assets.
We evaluate the impairment of our oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. For example, in the first quarter of 2020, we recorded a non-cash pre-tax asset impairment charge of $289 million on proved properties in Utah and certain California locations.
We have significant concentrations of credit risk with our customers and the inability of one or more of our customers to meet their obligations or the loss of any one of our major oil and natural gas purchasers may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We have significant concentrations of credit risk with the purchasers of our oil and natural gas. For the year ended December 31, 2022, sales to PBF Holding, Tesoro Refining and Marketing, and Phillips 66 accounted for approximately 33%, 16%, and 10%, respectively, of our sales. This concentration may impact our overall credit risk because our customers may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. If the purchasers of our oil and natural gas become insolvent, we may be unable to collect amounts owed to us. Also, if we were to lose any one of our major customers, the loss could cause us to cease or delay both production and sale of our oil and natural gas in the area supplying that customer.
Due to the terms of supply agreements with our customers, we may not know that a customer is unable to make payment to us until almost two months after production has been delivered. We do not require our customers to post collateral to protect our ability to be paid.
Risks Related to Regulatory Matters
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change the requirements governing our operations, including the permitting approval process for oil and gas exploration, extraction, operations and production activities; well stimulation and other enhanced production techniques; and fluid injection or disposal activities, any of which could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy and plans.
Like other companies in the oil and gas industry, our operations are subject to a wide range of complex and stringent federal, state and local laws and regulations. Federal, state and local agencies may assert overlapping authority to regulate in these areas. See “Items 1 and 2. Business and Properties—Regulation of Health, Safety and Environmental Matters” for a description of laws and regulations that affect our business. Collectively, the effect of the existing laws and regulations is to potentially limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, and reduce the amount of oil and natural gas that we can produce from our wells below levels that would otherwise be possible. To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, fluid injection and disposal, stimulation, operation, maintenance, transportation, marketing, site remediation, decommissioning, abandonment and water recycling and reuse. These permits are generally subject to protest, appeal or litigation, which could in certain cases delay or halt projects, production of wells and other operations. Additionally, the regulatory burden on the industry increases our costs and consequently may have an adverse effect upon capital expenditures, earnings or competitive position. Failure to comply may result in the assessment of administrative, civil and criminal fines and penalties and liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting our operations.
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