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

OR

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

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

Title of each class Common Stock, par value $0.001 per share			Trading Symbol BRY			Name of each exchange on which registered Nasdaq Global Select Market

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. ☐

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 $362.7 million.

DOCUMENTS INCORPORATED BY REFERENCE

Table of Contents

Part I
Item 1 and 2. Business and Properties			1
Our Company			1
The Berry Advantage			2
Our Business Strategy			4
Our Capital Program			5
Our Areas of Operation - Development and Production			6
Our Well Servicing and Abandonment Business			8
Our Assets and Production Information			9
Our Reserves			11
Methods of Recovery and Marketing Arrangements			20
Title to Properties			23
Competition			23
Seasonality			23
Regulatory Matters			24
Human Capital Resources			34
Corporate Information			35
Item 1A. Risk Factors			35
Item 1B. Unresolved Staff Comments			61
Item 3. Legal Proceedings			61
Item 4. Mine Safety Disclosure			62
Part II
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			63
Item 6. Selected Financial Data			67
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations			68
Executive Overview			68
How We Plan and Evaluate Operations			69
Business Environment and Market Conditions			71
Certain Operating and Financial Information			74
Summary by Area			76
Results of Operations			76
Liquidity and Capital Resources			81
Balance Sheet Analysis			90
Non-GAAP Financial Measures			91
Critical Accounting Policies and Estimates			95
Inflation			97
Cautionary Note Regarding Forward-Looking Statements			98
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			100
Item 8. Financial Statements and Supplementary Data			102
Index to Financial Statements and Supplementary Data			102
Report of Independent Registered Public Accounting Firm			103

Consolidated Balance Sheets			104
Consolidated Statements of Operations			105
Consolidated Statements of Stockholders' Equity			106
Consolidated Statements of Cash Flows			107
Notes to Consolidated Financial Statements			108
Supplemental Oil & Natural Gas Data (Unaudited)			138
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			144
Item 9A. Controls and Procedures			144
Item 9B. Other Information			145
Part III
Item 10. Directors, Executive Officers and Corporate Governance			146
Item 11. Executive Compensation			146
Item 12. Security Ownership of Certain Beneficial Owners and Management			146
Item 13. Certain Relationships and Related Transactions and Director Independence			146
Item 14. Principal Accounting Fees and Services			146
Part IV
Item 15. Exhibits			147
Item 16. Form 10-K Summary			150
Glossary of Commonly Used Terms			151
Signatures			159

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.

Part I

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

As of October 1, 2021, we have operated in two business segments: (i) development and production (“D&P”) (ii) well servicing and abandonment. The development and production segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which became a reportable segment (well servicing and abandonment) under U.S. GAAP.

We are a western United States independent upstream energy company focused on the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California. As further discussed below, in the fourth quarter of 2021, we diversified our operations with the acquisition of a business with well servicing and abandonment capabilities.

Our upstream development and production assets, in the aggregate, are characterized by high oil content, with 100% oil content for our California assets, and are in rural areas with low population. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. For example, the cost to drill and complete the different types of our wells in California is approximately $400,000 per well. The vertical wells in Utah operations cost approximately $1.5 million per well. In contrast, wells in typical unconventional resource plays cost $5 million to $10 million to drill and complete. The California oil market has Brent-linked pricing which in recent history realizes premium pricing to WTI. In the past five years Brent pricing has averaged almost $5 above WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin, which has more than 150 years of production history and substantial oil remaining in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics are well understood, which enables predictable, repeatable, low geological risk and low-cost development opportunities. We also have upstream assets in the low-operating cost, oil-rich reservoirs in the Uinta basin of Utah. In January 2022, we divested our natural gas properties in the Piceance basin of Colorado.

In the fourth quarter of 2021, we acquired one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J Well Services. This acquisition creates a strategic growth opportunity for Berry. It 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, C&J Well Services 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. We believe that C&J Well Services is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as an orphan well), and there are approximately 35,000 idle wells estimated to be in California according to third-party sources.

Since our Initial Public Offering in 2018, we have demonstrated our commitment to returning a substantial amount of capital to shareholders, delivering $134 million to our shareholders through dividends and share repurchases through 2021. In 2022, we initiated a new shareholder return model, which is designed to significantly increase cash returns to our shareholders from our discretionary free cash flow, which we define as cash flow from

operations less regular fixed dividends and the capital needed to hold production flat. Like our business model, this new shareholder returns model is simple and further demonstrates our commitment to return capital to our shareholders.

We believe that the successful execution of our strategy across our low-declining, oil-weighted production base coupled with extensive inventory of identified drilling locations with attractive full-cycle economics will support our objectives to generate Levered Free Cash Flow to fund our operations, optimize capital efficiency, and return meaningful capital to stockholders, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles. “Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less capital expenditures, interest expense and dividends. “Adjusted EBITDA” is also a non-GAAP financial measure defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual and infrequent items. These supplemental non-GAAP financial measures are used by management and external users of our financial statements. Please see “Management’s Discussion and Analysis—“Non-GAAP Financial Measures” for reconciliations of Levered Free Cash Flow and Adjusted EBITDA to net cash provided by operating activities and of Adjusted EBITDA to net income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP.

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

The Berry Advantage

Our business model is similar to that of a manufacturer. The foundation of our business model is our base production, which is the production that comes from our existing, producing wells. In terms of maintaining California production levels year over year, our base production, on average, accounts for 90% of our total annual production, and the remaining 10% comes from the drilling of new wells or the workover of existing wells. We also have a manageable annual corporate decline rate of approximately 13%, with abundant inventory of new drill and workover opportunities and predictable costs, all which provides clear visibility to our potential cash flow. Over the price cycle these advantages allow us to generate significant cash flow.

We believe the following competitive advantages will allow us to successfully execute our business strategy and to meet our objectives to generate Levered Free Cash Flow to fund our operations, optimize capital efficiency, and return meaningful capital to stockholders, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles:

•Stable, long-lived, oil-weighted conventional asset base with low and predictable production decline rates. The overwhelming majority of our interests are in properties that have produced oil for decades. As a result, 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. The properties, especially our California assets, 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. For example, our current corporate annual decline rate is approximately 13%. One advantage of our decline curve is that it provides strong visibility into our cash flows and it is manageable. In California, production from existing wells, which requires little to no additional capital to continue to produce, provides on average 90% of the production needed to maintain existing levels. The

•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. We expect to be able to generate attractive rates of return and positive Levered Free Cash Flow through typical commodity price cycles, which, if prolonged, would allow us to continue returning meaningful capital to stockholders, maintain current production levels and fund organic and strategic growth, among other things. For example, our proved undeveloped (“PUD”) reserves in California are projected to average single-well rates of return of approximately 60% based on the assumptions prepared by DeGolyer and MacNaughton in our SEC reserves report as of December 31, 2021. These margins would be substantially greater based on the current strip prices which are more than 15% higher presently than the prices used for the 2021 reserve calculation. We currently operate approximately 98% 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 relative insulation from service cost inflation pressures. Our high degree of operational control and relatively stable and predictable cost environment provide us significant 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 65% to 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 2018 IPO, our capital structure has consisted of common stock and $400 million of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”). As of December 31, 2021, we had $215 million of liquidity, consisting of $22 million of cash on hand and $193 million available for borrowings under our 2021 RBL Facility. As of December 31, 2021, our unhedged Leverage Ratio (as defined in our RBL Facility) was 2.0:1.0. In addition, we have minimal long-term service or fixed-volume delivery commitments. 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 deep technical, operational and strategic management experience to optimize the value of our assets and the Company. We are focused on the principles of operating within Levered Free Cash Flows while maintaining or growing our production and growing 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 Levered Free Cash Flow and maintain balance sheet strength and flexibility through commodity price cycles. We are committed to operating within Levered Free Cash Flow, which includes funding our capital program and paying interest and fixed dividends, as declared by our Board of Directors. Additionally, our objective is to achieve and maintain a long-term, through-cycle unhedged Leverage Ratio (as defined in our RBL Facility) between 1.0x and 2.0x, or lower.

•Return capital to our stockholders. Our objective is to take advantage of our strong 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, 2021, we have returned approximately $134 million to our shareholders through dividends and share repurchases, representing 122% of our IPO proceeds. Through December 31, 2021, we repurchased approximately 7% of our outstanding shares for approximately $52 million leaving approximately $48 million authorized and available for future repurchases under the program. Additionally, in February 2020, our Board of Directors adopted a program to spend up to $75 million for the opportunistic repurchase of our 2026 Notes, although we have not yet repurchased any notes under this program. 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.”

◦60% predominantly in the form of cash variable dividends to be paid quarterly, as well as opportunistic debt repurchases; and

◦40% in the form of discretionary capital, to be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention

•Grow or maintain production and reserves in a capital efficient manner while producing positive internally generated Levered Free Cash Flow. We intend to continue to allocate capital in a disciplined manner to projects that will produce predictable and attractive rates of return and positive Levered Free Cash Flow. We 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 growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins.

•Proactively and collaboratively engage in matters related to regulation, the environment and community relations. We seek to continue to work closely with regulators and legislators throughout the rule making process to minimize adverse impacts that new legislation and regulations might have on our ability to maximize our resources and to mitigate adverse impacts to our permitting process. Additionally, we have found that constructive dialogue with regulatory representatives can help avert compliance and permitting issues. We believe that running our operations in a manner that protects the safety and health of the environment and all those that may be impacted by our operations and is in compliance with existing laws and regulations is not only the right way to run our business, but it helps us build and maintain credibility with the relevant agencies governing our operations, as well as positive relationships with the communities

in which we operate. With ultimate oversight by our Board of Directors, Environmental, Health & Safety (“EH&S”) 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 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.

•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 also seek to protect our operating expenses through fixed-price gas purchase agreements, hedging contracts 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. We protected a significant portion of our cash flows in 2021, and have sought to protect a significant portion of our anticipated cash flows in 2022, as well as a portion in 2023 through 2024, using our commodity hedging program. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge gas purchases to protect against price increases. In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. We review our hedging program continuously as market conditions change and make our hedging decisions using a wide range of market data and analysis.

•Contribute to the energy transition. We believe that oil and gas will remain an important part of the energy landscape going forward. We recognize the oil and gas industry’s role in the energy transition and we are determined to be part of the solution. This is the new energy reality. We have newly acquired capabilities to support the State of California's orphaned wells and fugitive emissions initiatives. With the fourth quarter 2021 acquisition of CJWS, we can reduce state-wide fugitive emissions, which are primarily methane, the most damaging of the greenhouse gases, by plugging and abandoning orphan and idle wells today. Additionally, we are continuing to hone our medium and long-term environmental priorities as it relates to ESG, 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, 2021 and 2020 our total capital expenditures were approximately $133 million and $76 million, respectively, on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement spending. Approximately 79% and 12% of capital expenditures for the year ended December 31, 2021 was directed to California oil and Utah operations, respectively. We increased our 2021 capital program compared to 2020, in response to the improved oil price environment and the improving global and national economic environment.

Our 2021 capital program was heavily weighted in the middle of the year and resulted in increases in our average daily production each quarter throughout 2021. As a result of capital deployed, production in the last quarter of 2021 was 5% higher than the last quarter of 2020. This is indicative of the positive response we get from our assets with strategic capital deployment. The year-over-year production results were impacted by the significant

Our 2022 capital expenditure budget for D&P operations and corporate activities is approximately $125 to $135 million, excluding approximately $8 million for C&J Well Services, which we expect will keep our annual production flat. We currently anticipate oil production will be approximately 92% of total production volume in 2022, compared to 88% in 2021 and 88% in 2020, with the change largely due to the Piceance natural gas properties divestiture in January 2022. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2022 capital development programs from cash flow from operations. The execution of these plans requires that we timely obtain certain regulatory permits and approvals, which we may not be able to obtain on a timely basis or at all. 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.

In 2021 we began to spend capital on environmental projects related to our sustainability or “ESG” initiatives. We plan to increase capital spent on these ESG projects in 2022, which will include solar generation to power operations and equipment efficiency improvements that will decrease our carbon emissions.

We currently expect to employ two to three drilling rigs in California during 2022. Additionally, we currently expect to drill approximately 120 to 130 development wells and 5 to 10 delineation wells during 2022. Of the development capital in 2022 we anticipate approximately 80-85% in California and 15-20% in Utah.

Exclusive of the capital expenditures noted above, for the full year 2021, we spent approximately $19 million on plugging and abandonment activities, exceeding our annual obligation requirements under the California idle well management plan. In 2022, 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 predominant development and production operating area is in California, and we also have operations in Utah. In January 2022 we divested our Colorado operating area.

California

California is and has been one of the most productive oil and natural gas regions in the world. According to the U.S. Energy Information Administration as of 2015, 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 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 allowed continuing discoveries of stratigraphic, structural and non-structural traps. Most oil accumulations discovered in the San Joaquin basin occur in the Eocene age

We currently hold approximately 14,000 net acres in the San Joaquin basin in Kern County, of which 91% is held by production and fee interest. Approximately 13% 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:

•West California operations consist of: (i) our North Midway-Sunset sandstone properties, where we use cyclic and continuous steam injection to develop these known reservoirs; (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 and our McKittrick Field property, which is a newer steamflood development with potential for infill and extension drilling. Also located here is our North Midway-Sunset thermal diatomite properties, which requires 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 pending a study co-led by Lawrence Livermore National Laboratory and CalGEM of the practice to address surface expressions experienced by certain operators, we have not included these properties in our plans through 2023. Please see “—Regulation of Health, Safety and Environmental Matters—Additional CalGEM Actions on Oil and Gas Activities” for more information.

•East California operations consist of our Poso Creek property, which is an active mature shallow, heavy oil asset that we continue to develop across the property. 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 81% of our total proved reserves at December 31, 2021. California accounted for 22.0 mboe/d, or 80%, of our average daily production for the year ended December 31, 2021.

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 supply approximately 18% of our steam needs and approximately 65% 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 currently also sell surplus power produced by two of our cogeneration facilities under power purchase agreement (“PPA”) contracts with California utility companies. We also own 62 conventional steam generators to help satisfy the steam required by our operations.

In addition, we own gathering, treatment, water recycling and softening facilities, as well as storage facilities, in California that currently have excess capacity, reducing our need to spend capital to develop nearby assets and generally allowing us to control certain operating costs. Approximately 92% of our California oil production is sold through pipeline connections.

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 and Lake Canyon areas in Utah target the Green River and Wasatch formations that produce oil and natural gas at depths ranging from 5,000 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 90,000 net acres in the Uinta basin, of

Our Uinta basin proved reserves represented approximately 15% of our total proved reserves at December 31, 2021 and accounted for 4.2 mboe/d or 15% of our average daily production for the year ended December 31, 2021.

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 93% of the gas gathered at these facilities is produced from wells that we operate. Current throughput at the processing plant is 15-17 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 85 mbbl/d in 2020. Approximately 84% of Utah’s oil production in 2020 came from the Uinta basin in Duchesne and Uintah counties.

Piceance Basin, Colorado

The Piceance basin in northwestern Colorado is a natural gas play. In January 2022 we divested our Piceance Basin assets. Our Piceance basin proved reserves represented approximately 4% of our total proved reserves at December 31, 2021 and accounted for 1.2 mboe/d, or 4%, of our average daily production for the year ended December 31, 2021.

In late 2021, we acquired one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J Well Services, LLC. C&J Well Services provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services, and water logistics with a constant focus on maintaining the highest reliability standards and safety record. Our 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, we perform plugging and abandonment services on wells at the end of their productive life, which creates a strategic growth opportunity for Berry. C&J Well Services 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, C&J Well Services 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. We believe that C&J Well Services is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as an orphan well), and there are approximately 35,000 idle wells estimated to be in California according to third-party sources.

Through C&J Well Services we operate a fleet of 73 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

•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 well bore; 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 276 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 1,630 pieces of rental equipment on our water logistics side.

Our Assets and Production Information

For the year ended December 31, 2021, we had average net production of approximately 27.4 mboe/d, of which approximately 88% was oil and approximately 80% was in California. In California, our average production for the year ended December 31, 2021 was 22.0 mboe/d, of which 100% was oil. Our California production in 2021 includes Placerita operations contributing average daily production in of over 800 boe/d through the end of October 2021 when those assets were divested. Additionally, we divested all of our properties in the Piceance basin of Colorado in January 2022, which had production of 1.2 mboe/d in 2021.

The table below summarizes our average net daily production for the years ended December 31, 2021 and 2020:

			Average Net Daily Production(1) for the Year Ended December 31,
			2021												2020
			(mboe/d)						Oil (%)						(mboe/d)						Oil (%)
California(2)			22.0						100		%				22.9						100		%
Utah			4.2						51		%				4.3						50		%
			26.2						88		%				27.2						88		%
Colorado(3)			1.2						2		%				1.3						2		%
Total			27.4						88		%				28.5						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 over 800 boe/d prior to the sale.

(3)    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, 2021 and 2020.

			Year Ended December 31,
			2021						2020
Average daily production(1):
Oil (mbbl/d)			24.2						25.0
Natural gas (mmcf/d)			17.1						18.5
NGLs (mbbl/d)			0.4						0.4
Total (mboe/d)(2)			27.4						28.5

(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, 2021, the average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.

Our Development Inventory

We have an extensive inventory of low-geologic risk, high-return development opportunities. As of December 31, 2021, we identified 10,414 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 98% 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, 2021, the combined net acreage covered by leases expiring in the next three years represented approximately 11% of our total net acreage, of which 91% is in Utah. Our high degree of operational control, together with the large portion of our acreage that is held by production, and the speed with which we are able to drill and complete our wells in

The following table summarizes certain information concerning our active producing and identified development assets as of December 31, 2021:

			Acreage												Net Acreage Held By Production and Fee Interest(%)						Producing Wells, Gross(3)(4)						Average Working Interest (%)(4)(5)						Net Revenue Interest (%)(4)(6)						Identified Drilling Locations(7)
			Gross						Net(1)(2)																														Gross						Net
California			18,823						14,111						91		%				2,448						97		%				94		%				9,981						9,942
Utah			107,069						90,108						83		%				970						95		%				79		%				433						369
Colorado			9,259						6,780						100		%				169						72		%				62		%				—						—
Total			135,151						110,999						85		%				3,587						95		%				90		%				10,414						10,311

(1)    Represents our weighted-average interest in our acreage.     

(2)    Of which approximately 13% are BLM acres in California and 32% are BLM acres in Utah.

(3)    Includes 483 steamflood and waterflood injection wells in California.

(4)    Excludes 90 wells in the Piceance basin each with a 5% working interest. We divested all of our Colorado Piceance basin assets in January 2022.

(5)    Represents our weighted-average working interest in our active wells.

(6)    Represents our weighted-average net revenue interest for the year ended December 31, 2021.

(7)    Our total identified drilling locations include approximately 719 gross (715 net) locations associated with PUDs as of December 31, 2021, including 90 gross (90 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, 2021, we had estimated total proved reserves of 97 mmboe, an increase from 95 mmboe, as of December 31, 2020. Our overall proved reserves increased 12 mmboe, or 13%, before production of 10 mmboe, the majority of which is due to price revisions. We replaced 120% of our production with additional proved reserves. Based on current Brent strip pricing we would expect a further improvement in the 2022 proved reserves.

The majority of our reserves are composed of crude oil in shallow, long-lived reservoirs. As of December 31, 2021, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our proved reserves were approximately $1.2 billion and $1.5 billion, respectively. These values represent significant increases from the prior year end of $516 million and $520 million. 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, 2021, approximately 81% of our proved reserves and approximately 91% of the PV-10 value of our proved reserves are derived from our assets in California. We also have approximately 15% of our proved reserves and approximately 8% of the PV-10 value in the Uinta basin in Utah, a mature, light-oil-prone play with significant undeveloped resources. Approximately 4% of our proved reserves and only 1% of the related PV-10

The tables below summarize our estimated proved reserves and related PV-10 by category as of December 31, 2021:

			Proved Reserves as of December 31, 2021(1)(5)
			Oil (mmbbl)						Natural Gas (bcf)						NGLs (mmbbl)						Total (mmboe)(2)						% of Proved						% Proved Developed						Capex(3) ($MM)						PV-10(4) ($MM)
PDP			47						60						1						58						60		%				90		%				14						911
PDNP			6						—						—						6						6		%				10		%				17						128
PUD			33						2						—						33						34		%				—		%				451						474
Berry total proved reserves			86						62						1						97						100		%				100		%				482						1,513
California total proved reserves			79						—						—						79																		455						1,374

(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 $69.47 per bbl Brent for oil and natural gas liquids (“NGLs”) and $3.64 per mmbtu Henry Hub for natural gas at December 31, 2021. The volume-weighted average prices over the lives of the properties were estimated at $65.10 per bbl of oil and condensate, $36.08 per bbl of NGLs and $3.98 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, 2021.

(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.

(5)    In January 2022 we divested our Piceance basin properties in Colorado.

The following table summarizes our estimated proved reserves and related PV-10 by area as of December 31, 2021. 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. We divested the Colorado properties in the Piceance basin in January 2022.

			Proved Reserves as of December 31, 2021(1)
			California (San Joaquin basin)												Utah (Uinta basin)						Colorado (Piceance basin)(5)						Total
Proved developed reserves:
Oil (mmbbl)			47												6						—						53
Natural Gas (bcf)			—												35						25						60
NGLs (mmbbl)			—												1						—						1
Total (mmboe)(2)(3)			47												13						4						64
Proved undeveloped reserves:
Oil (mmbbl)			32												1						—						33
Natural Gas (bcf)			—												2						—						2
NGLs (mmbbl)			—												—						—						—
Total (mmboe)(3)			32												1						—						33
Total proved reserves:
Oil (mmbbl)			79												7						—						86
Natural Gas (bcf)			—												37						25						62
NGLs (mmbbl)			—												1						—						1
Total (mmboe)(3)			79												14						4						97
PV-10 ($million)(4)			$	1,374											$	124					$	15					$	1,513

(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 $69.47 per bbl Brent for oil and NGLs and $3.64 per mmbtu Henry Hub for natural gas at December 31, 2021. The volume-weighted average prices over the lives of the properties were $65.10 per bbl of oil and condensate, $36.08 per bbl of NGLs and $3.98 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 Industry—Oil, natural gas and NGL prices are volatile and directly affect our results.”

(2)    For proved developed reserves approximately 10% of total and 11% 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 year ended December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.

(4)    For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—PV-10.” PV-10 does not give effect to derivatives transactions.

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

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.

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, 2021:

			At December 31, 2021
			(in millions)
California PV-10			$	1,374
Utah PV-10			124
Colorado PV-10			15
Total Company PV-10			1,513
Less: present value of future income taxes discounted at 10%			(280)
Standardized measure of discounted future net cash flows			$	1,233

Proved Reserves Additions

Our overall proved reserves increased 12 mmboe, or 13%, before production. A majority of this increase was a result of the higher price environment and extensions. We replaced 120% of our production with additional proved reserves. The total changes to our proved reserves from December 31, 2020 to December 31, 2021 were as follows:

			California (San Joaquin basin)																					Utah (Uinta basin)						Colorado (Piceance basin)						Total
			(in mmboe)(1)
Beginning balance as of December 31, 2020			87																					7						1						95
Extensions and discoveries			1																					2						—						3
Revisions of previous estimates			(1)																					7						3						9
Purchases of minerals in place(2)			—																					—						—						—
Sales of minerals in place(3)			—																					—						—						—
Current year production			(8)																					(2)						—						(10)
Ending balance as of December 31, 2021			79																					14						4						97

(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 year ended December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.

(2)    Purchases of minerals in place were less than 1 mmboe.

(3)    Sales of minerals in place were less than 1 mmboe.

Extensions. During 2021, we added 3 mmboe of proved reserves from extensions in our California and Utah properties.

Revisions of Previous Estimates.

Revisions related to price - Product price changes affect the proved reserves we record. For example, higher prices generally increase the economically recoverable reserves in all of our operations because the extra margin extends their expected life and renders more projects economic. Conversely, when prices drop, we experience the opposite effects. In 2021, our total net positive price revision was 9 mmboe in California, 6 mmboe in Utah, and 3 mmboe in Colorado.

Revisions related to performance - Performance-related 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 data. In 2021, we had negative technical revisions of 10 mmboe in California, which was

partially offset by positive technical revisions of 1 mmboe in the Rockies. The negative technical revisions resulted primarily from a strategic change in development plans in our Hill Tulare properties to a more focused approach on infill drilling rather than extending our proved developed area, as well as adjustments made to our thermal Diatomite development plans.

Current Year Production - Please refer to “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Certain Operating and Financial Information” for discussion of our current year production.

Proved Undeveloped Reserves Changes

Our California proved undeveloped reserves decreased 7 mmboe in 2021 largely due to reclassifications to proved developed reserves. Our development program in 2021 was focused on maintaining production with minimal capital spent on growth limiting the proved undeveloped reserves additions. The total changes to our proved undeveloped reserves from December 31, 2020 to December 31, 2021 were as follows:

			California (San Joaquin and Ventura basins)						Utah (Uinta basin)						Colorado (Piceance basin)																								Total
			(in mmboe)(1)
Beginning balance as of December 31, 2020			39						—						—																								39
Extensions and discoveries			1						1						—																								2
Revisions of previous estimates			(3)						—						—																								(3)
Reclassifications to proved developed			(5)						—						—																								(5)
Ending balance as of December 31, 2021			32						1						—																								33

(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 year ended December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.

Extensions. During 2021, we added 2 mmboe of proved undeveloped reserves from extensions based on drilling results from unproven locations in Midway Sunset, McKittrick, and Utah.

Revisions of previous estimates.

Revisions related to price - In 2021, our net positive price revision on proved undeveloped reserves were approximately 1 mmboe in California, which was the result of higher prices due to the current commodity price environment.

Revisions related to performance - In 2021, our net negative performance-related revision on proved undeveloped reserves was 4 mmboe in California which resulted primarily from our thermal Diatomite and Hill Tulare areas.

Reclassifications to proved developed. During 2021, we transferred approximately 5 mmboe of proved undeveloped reserves to the proved developed category due to development drilling activity in 2021. Our development of proved undeveloped reserves during much of 2020 and 2021 was significantly limited by the severe downturn in the industry, which impacted not only our capital over those two years but also our strategic development approach. With our 2021 development program, we converted 4.5 mbbls of our beginning-of-the year inventory of proved undeveloped reserves, spending approximately $48 million of capital. We expect to have sufficient future capital to develop our proved undeveloped reserves at December 31, 2021 within five years. Prices substantially below current levels for a prolonged period of time may require us to reduce expected capital expenditures over the next five years, potentially impacting either the quantity or the development timing of proved

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. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability and include production and well test data, downhole completion information, geologic data, 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 Registered 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 Industry—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.”

Determination of Identified Drilling Locations

Proven Drilling Locations

Based on our reserves report as of December 31, 2021, we have approximately 719 gross (715 net) drilling locations attributable to our proved undeveloped reserves, compared to 808 gross (805 net) as of December 31, 2020. The decrease in drilling locations attributable to our proved undeveloped reserves is primarily due to the 2021 drilling activity. 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

Unproven Drilling Locations

We have also identified a multi-year inventory of 9,695 gross (9,596 net) unproven drilling locations as of December 31, 2021, compared to 9,565 gross (9,533 net) unproven drilling locations as of December 31, 2020. 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, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry—We 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, 2021.

			PUD Drilling Locations (Gross)												Unproven Drilling Locations (Gross)												Total Drilling Locations (Gross)
			Oil and Natural Gas Wells						Injection Wells						Oil and Natural Gas Wells						Injection Wells						Oil and Natural Gas Wells						Injection Wells
California			611						90						7,328						1,952						7,939						2,042
Utah			18						—						415						—						433						—
Colorado(1)			—						—						—						—						—						—
Total Identified Drilling Locations			629						90						7,743						1,952						8,372						2,042

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

			Year Ended December 31,
			2021						2020						2019
SJV Midway Sunset
Total production(1):
Oil (mbbls)			5,666						5,933						5,543
Natural gas (bcf)			—						—						—
NGLs (mbbls)			—						—						—
Total (mboe)(2)			5,666						5,933						5,543

			Year Ended December 31,
			2021						2020						2019
SJV Belridge Hill
Total production(1):
Oil (mbbls)			1,505						1,280						1,312
Natural gas (bcf)			—						—						—
NGLs (mbbls)			—						—						—
Total (mboe)(2)			1,505						1,280						1,312

(1)    Production represents volumes sold during the period.

(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, 2021, the average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.

Productive Wells

As of December 31, 2021, we had a total of 3,587 gross (3,417 net) productive wells (including 483 gross and net steamflood and waterflood injection wells), approximately 95% of which were oil wells. Our average working interests in our productive wells is approximately 96%. All of our Uinta basin oil wells produce associated gas and NGLs and wells in our Piceance basin are primarily gas and also produce condensates. 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.

The following table sets forth our productive oil and natural gas wells (both producing and capable of producing) as of December 31, 2021.

			California (San Joaquin basin)						Utah (Uinta basin)						Colorado (Piceance basin)						Total
Oil
Gross(1)			2,448						970						—						3,418
Net(2)			2,374						922						—						3,296
Gas
Gross(1)(3)			—						—						169						169
Net(2)(3)			—						—						121						121

(1)    The total number of wells in which interests are owned. Includes 483 steamflood and waterflood injection wells in California.

(2)    The sum of fractional interests.

(3)    Excludes 90 wells in the Piceance basin each with a 5% working interest.

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, 2021.

			California (San Joaquin basin)																								Utah and Other (Uinta and Piceance basins)						Total
Developed(1)
Gross(2)			7,078																								47,863						54,941
Net(3)			7,053																								43,346						50,399
Undeveloped(4)
Gross(2)			11,746																								68,465						80,211
Net(3)			7,059																								53,542						60,601

(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.

Participation in Wells Being Drilled

As of December 31, 2021, we were not participating in any uncompleted wells.

Drilling Activity

The following table shows the net development wells we drilled during the periods indicated. 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. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

			California (San Joaquin and Ventura basins(3))																								Utah (Uinta basin)						Colorado (Piceance basin)						Total
2021
Oil(1)			181																								10						—						191
Natural Gas			—																								—						—						—
Dry			—																								—						—						—
2020
Oil(1)			45																								—						—						45
Natural Gas			—																								—						—						—
Dry			—																								—						—						—
2019
Oil(1)(2)			335																								3						—						338
Natural Gas			—																								—						—						—
Dry			—																								—						—						—

(1)    Includes injector wells.

(2)    Includes 50 wells that had not yet been connected to gathering systems in California.

(3)    Effective October 2021, we completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles County, California, which included 1 well in 2019, 1 well in 2020 and zero wells in 2021.

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, 2021, the volumes contracted to be processed were approximately 4,560 mcf/d through February 2023. We have significantly more production than the amounts committed for delivery and have the ability to secure additional volumes of products as needed.

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 95% 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.

State

Project Type

Well Type

Completion Type

Recovery Mechanism

California

Thermal Sandstones

Vertical / Horizontal

Perforation/Slotted liner/gravel pack

Continuous and cyclic steam injection

California

Thermal Diatomite

Vertical

Short interval perforations

High-pressure cyclic steam injection

California

Hill Diatomite (non-thermal)

Vertical

Hydraulic stimulation, low intensity pin point

Pressure depletion augmented with water injection

Utah

Uinta

Vertical / Horizontal

Low intensity hydraulic stimulation

Pressure 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, primarily 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 $400,000 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 Industry—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 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 aggregated cost of steam generation. The natural gas we purchase to generate steam and electricity is primarily based on California price indexes, and in some cases includes transportation charges.

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 65% to 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 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.

For the year ended December 31, 2021, excluding the Placerita cogeneration facility which we divested in October 2021, we sold approximately 383,000 megawatt-hours (“MWhs”) per day of cogen power into the grid and on average consumed approximately 291 MWhs per day of cogen power for lease operations. The four cogeneration facilities produced an average of approximately 25,000 barrels of 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 two of our cogeneration facilities under long-term PPAs approved by the California Public Utilities Commission (the “CPUC”) to two California investor-owned utilities, Southern California Edison Company (“Edison”) and Pacific Gas and Electric (“PG&E”). These PPAs expire in various years between 2022 and 2026.

Principal Customers

For the year ended December 31, 2021, sales to Tesoro Refining and Marketing, PBF Holding, Kern Oil & Refining, and Phillips 66 accounted for approximately 30%, 16%, 14%, and 12% respectively, of our sales. At December 31, 2021, trade accounts receivable from three customers represented approximately 28%, 13% and 11% 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”.

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.

The oil and natural gas industry is highly competitive. In our upstream development and production 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 the availability of 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. Our revenues and earnings can be affected by several factors, including changes in competition, fluctuations in drilling and completion activity, 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 Industry—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. ”

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.

Seasonality

Seasonal weather conditions can impact our drilling, production and well servicing activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling and completion objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may have been and in the future may be impacted by ice and snow in the winter, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as by wild fires and rain.

Natural gas prices can fluctuate based on seasonal and other market-related impacts. We purchase significantly more gas than we sell to generate steam and electricity in our cogeneration facilities for our producing activities. As a result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of this exposure by selling excess electricity from our cogeneration operations to third parties. The pricing of these electricity sales is closely tied to the purchase price of natural gas. These sales are generally higher in the summer months as they include seasonal capacity amounts. We also hedge a significant portion of the gas we expect to consume. We recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our operations in California, which are typically lower cost gas prices.

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.

Collectively, the effect of the existing laws and regulations is to potentially limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, and reduce the amount of oil and natural gas that we can produce from our wells below levels that would otherwise be possible. Additionally, the regulatory burden on the industry increases our costs and consequently may have an adverse effect upon operations, capital expenditures, earnings and our competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and future prospects.

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 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.

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 may result in delays in the issuance of such permits and approvals and the imposition of 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, typically through either an environmental review or an exemption by a state or local agency.

In Kern County, where all of our California assets are now located, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (“Kern County EIR”) covering oil and gas operations in Kern County which was certified by the Kern County Board of Supervisors in 2015. In addition to CalGEM, other state agencies have relied on the Kern County EIR to satisfy the CEQA requirements in connection with permitting and project approval decisions for oil and gas projects in unincorporated Kern County. In 2020, a group of plaintiffs challenged the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County made certain revisions to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County elected to prepare a supplemental EIR which was approved by the Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs in March 2021, a Kern County Superior Court judge suspended use of the supplemental EIR, stopping the issuance of new oil and gas permits by Kern County (the “Kern County Permit Suspension”) in October 2021, pending judicial review of the supplemental EIR and a determination of its compliance with CEQA requirements by the Kern County Superior Court. A hearing on the matter by the Kern County Superior Court is scheduled for April 2022. We cannot predict the outcome of this hearing on the Kern County EIR or whether it will result in the imposition of more onerous permit requirements or other requirements or restrictions on land use and exploration and production activities.

Importantly, the Kern County Ruling and the Kern County Permit Suspension did not invalidate existing permits and our plans and operations have not been materially impacted to date. Until Kern County is able to resolve the challenges regarding the sufficiency of the Kern County EIR and resume the ability to issue permits, our ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating to CalGEM compliance with CEQA. Demonstrating compliance with CEQA without being able to reference the Kern County EIR is a more technically, time and cost intensive process and may, among other things, require that we conduct an environmental impact review. As a result, we together with other Kern County operators have experienced delays in the issuance of permits by CalGEM, as well as a more time- and cost- intensive permitting process. Approximately 10% of our current 2022 production plans is expected to come from the drilling of new wells, which requires the issuance of new permits, and the workover of existing wells; our existing producing wells are expected to contribute the other 90%. We believe that we have sufficient permit inventory to cover our drilling plans through the first quarter of 2022. However, our drilling plans for the remainder of the year, and therefore our current 2022 production goals, may be impacted by our ability to timely obtain the required permits and approvals to support those planned activities, particularly if the Kern County Permit Suspension continues or if there are further delays in or new restrictions imposed upon the issuance or renewal of permits and approvals required for oil and gas activities in Kern County. If we are unable to obtain the permits required to support our current 2022 drilling plans, we may reduce our planned capital expenditures or deploy that capital to other activities. Additionally, any postponement or elimination of our development drilling program could result in a reduction of proved reserves volumes and materially affect our business, financial condition and results of operations. In the future, if we are

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. The lawsuit is ongoing and 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 Kern County EIR is ultimately deemed sufficient and reinstated.

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 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 EPA, amongst other measures. The State responded in October 2021 with a proposed compliance plan but, to date, 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 the State 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 for 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 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. Changes in the process for approving infill wells has the potential to delay permitting injection and other activities, or otherwise result in increased compliance costs on our operations. Our 2022 plans, as well as potentially our future plans, may be

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, CalgGEM 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.

We have submitted an idle well management plan and are fulfilling the conditions of that plan to meet our obligations. In 2021, we spent approximately $19 million on plugging and abandonment activities, exceeding our annual obligation requirements under our idle well management plan. In 2022 we 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.

Additionally, in the fourth quarter of 2021, we acquired C&J Well Services, a profitable new business line, to provide standard well services to the industry in California and to accelerate the reduction of fugitive emissions by plugging and abandoning idle wells across California for ourselves and other operators, as well as the State of California. We believe that C&J Well Services is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as an orphan well), and 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 September 2020, the California Governor issued an executive order that seeks to reduce both the supply of and demand for fossil fuels in the state. The executive order 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). The executive order also directed CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations. In response to the executive order, in October 2021, CalGEM released for public comment a “discussion draft” proposed regulation that would prohibit new wells and facilities within a 3,200-foot setback area from homes, schools, hospitals, nursing homes, and other sensitive locations. The proposed regulation would also require pollution controls for existing wells and facilities within the same 3,200-foot setback area. CalGEM is currently in the process of conducting an economic analysis of the proposed rule. Following this analysis, CalGEM will submit a proposed rule to the Office of Administrative Law and will begin an additional process of receiving formal comments and refinement of the proposal as needed before

Separately, in October 2020, the 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.

Restrictions on Oil and Gas Developments on Federal Lands

As of December 31, 2021, approximately 13% and 32% of our net acreage in California and Utah, respectively, is on federal land, which comprises approximately 14% and 22% of our total proved reserves in California and Utah, respectively, and approximately 19% and 28% of our PUD locations in California and Utah, respectively. The potential exists for additional federal restrictions on oil and gas activities on federal lands 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, effectively halting implementation of the leasing suspension. The federal government is appealing the district court decision, but the BLM has scheduled a lease sale to occur in the first quarter of 2022. 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 and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. Implementation of many of the recommendations in the DOI report will require 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.

Operations on Tribal Lands

As of December 31, 2021, approximately 74% of our net acreage in Utah is on tribal lands, which comprises approximately 74% of our total proved reserves in Utah, and approximately 72% 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. Our undeveloped thermal diatomite assets currently are not part of our near-term development plans, nor are any areas in California that would require well stimulation treatments (“WST”) (also known as

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 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 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. Only our undeveloped thermal diatomite assets require new high-pressure cyclic steam wells and those assets are currently not in our near-term development plans. Our 2022 plans do not include new high-pressure cyclic steam wells, nor did our 2020 and 2021 plans. Additionally, we have not been impacted by the hydraulic fracking announcement as our current plans do not require the development of assets requiring hydraulic fracturing in California.

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. In 2015, the BLM issued regulations regarding the public disclosure of chemicals used in stimulation treatments, well construction and integrity and management of waste fluids resulting from hydraulic fracturing activities on federal and tribal lands. While the BLM rescinded these regulations in 2017, the rescission is subject to ongoing legal challenge. Additionally, the regulations may be reconsidered under the Biden Administration. If the rule is reinstated, or a similar rule is promulgated, the outcome could materially impact our operations in the Uinta basin, where as of December 31, 2021, approximately 22% of our proved reserves in Utah were located on federal lands and approximately 74% 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.

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, 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.

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 Heath 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 safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines;

•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);

•U.S. Department of Interior regulations, which regulate oil and gas production activities on federal lands and impose 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;

•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,

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 development and production 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 September 2018, California adopted a law committing California, the fifth largest economy in the world, to the use of 100% zero-carbon electricity by 2045, and the Governor of California also signed an executive order committing California to total economy-wide carbon neutrality by 2045. Additionally, Governor Newsom requested that the CARB analyze pathways to phase out oil extraction across the state by no later than 2045. 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. 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. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the Securities and Exchange Commission announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

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. 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 Industry—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, 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 exploration and production activities, and reduce demand for the oil and natural gas we produce.”

Human Capital Resources

As of December 31, 2021, we had 1,224 employees, all of whom are located in the United States. Of those, 889 employees joined our organization in the fourth quarter of 2021 with the acquisition of CJWS. 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, 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.

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, neuro(a)typicality, 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 team is 17% women, our senior management team is 30% women, and our total workforce is approximately 18% women, which we believe is higher than the U.S. industry average based on available data.

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 EH&S 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. Information contained in or accessible through our website is not, and should not be deemed to be, part of this report.

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 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 our business, financial condition and results of operations may be materially and adversely affected.

•The marketability of our production is dependent upon the availability of transportation and storage facilities, most of which we do not control. If we are unable to access such facilities on commercially reasonable terms or at all, our access to markets for the commodities we produce could be restricted, which would likely cause interruption to operations, curtailment of production, and reduced revenues, among other adverse consequences.

•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.

•Unless we replace oil and natural gas reserves, our future reserves and production will decline.

•The drilling and production of oil and natural gas involves many uncertainties, some of which we do not control, that could adversely affect our results.

•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, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

•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.

•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.

•Our producing properties are located primarily in California, making us vulnerable to risks associated with having operations concentrated in this highly regulated geographic area.

•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 not be insured for, or our insurance may be inadequate to protect us against, these risks.

•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 environmental, social and governance (“ESG”) matters may impact our operations and our business.

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.

•Our business requires continual capital expenditures. We may be unable to fund these investments through operating cash flow or obtain additional capital on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or production.

•Inflation could adversely impact our ability to control our costs, including our operating expenses and capital costs.

•Our hedging activities, including those required by our 2021 RBL facility, limit our ability to realize the full benefits of increases in commodity prices. 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.

•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 RBL Facility is subject to periodic redeterminations and our lenders could reduce capital available to us for investment.

•We may not be able to generate sufficient cash to service our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, and these efforts may not be successful.

•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 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.

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 including the permitting approval process for oil and gas activities that could increase costs, restrict operations, and delay our implementation of, or cause us to change, our business strategy and plans.

•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 exploration and production activities, and reduce demand for the oil and natural gas we produce.

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 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 applicable to “emerging growth companies,” which could make our common stock less attractive to investors.

•Our internal control over financial reporting is not currently required to meet all of the standards of Section 404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act standards could adversely affect our business and share price.

•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 that some stockholders may consider beneficial.

•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, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

•Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

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.

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. In we are unable to timely receive the permits and other approvals needed for our 2022 plans, or 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 now located, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (“Kern County EIR”) covering oil and gas operations in Kern County which was certified by the Kern County Board of Supervisors in 2015. In addition to CalGEM, other state agencies have relied on the Kern County EIR to satisfy the CEQA requirements in connection with permitting and project approval decisions for oil and gas projects in unincorporated Kern County. However, a group of plaintiffs challenged the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County made certain revisions to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County elected to prepare a supplemental EIR which was approved by the Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs in March 2021, a Kern County Superior Court judge suspended use of the supplemental EIR, stopping the issuance of new oil and gas permits by Kern County (the “Kern County Permit Suspension”) in October 2021, pending judicial review of the supplemental EIR and a determination of its compliance with CEQA requirements by the Kern County Superior Court. A hearing on the matter by the Kern County Superior Court is scheduled for April 2022. We cannot predict the outcome of this hearing on the Kern County EIR as supplemented or whether it will result in the imposition of more onerous permit application requirements or other requirements or restrictions on land use and exploration and production activities.

Importantly, the Kern County Ruling and the Kern County Permit Suspension did not invalidate existing permits and our plans and operations have not been materially impacted to date. Until Kern County is able to resolve the challenges regarding the sufficiency of the Kern County EIR and resume the ability to issue permits, CalGEM is serving as lead agency for CEQA purposes and our ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating to CalGEM an alternative way of complying with CEQA. Demonstrating compliance with CEQA independently - without being able to reference the Kern County EIR - is a more technically, time and cost intensive process and may, among other things, require that we conduct an environmental impact review. As a result, we together with other Kern County operators have experienced delays in the issuance of permits by CalGEM, as well as a more time- and cost- intensive permitting process. We believe that we currently have sufficient permit inventory to cover our drilling plan through the first quarter of 2022. However, our 2022 plans may be impacted by our ability to timely obtain the required permits and approvals to conduct planned operations through the remainder of the year, particularly if the Kern County Permit Suspension continues or if there are further delays in or new restrictions imposed upon the issuance or renewal of permits covering oil and gas activities in Kern County. 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.

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. The lawsuit is ongoing and we cannot predict its ultimate outcome or whether it could result in changes to CalGEM’s requirements for compliance with CEQA, even if the Kern County EIR is ultimately deemed sufficient and reinstated. The potential impact of this and potentially future litigation contributes to the uncertainty with respect to future requirements for demonstrating compliance with CEQA and therefore our ability to timely obtain the permits and approvals needed to conduct our operations.

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”.

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 exploration and production 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. Several bills have been introduced recently but failed to advance in the California State Legislature that restrict or prohibit the issuance or renewal of permits for various well stimulation and recovery techniques. Although these legislative efforts have failed, we cannot predict the outcome of future efforts. What's more, the regulatory burden on the industry increases our costs and consequently may have an adverse effect upon capital expenditures, earnings or competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and 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 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 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 September 2020, the California Governor issued an executive order that seeks to reduce both the supply of and demand for fossil fuels in the state. The executive order 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 emissions-producing vehicles; (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. The executive order also directed CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations.

•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 October 2021, CalGEM released for public comment a “discussion draft” proposed regulation that would prohibit new wells and facilities within a 3,200-foot setback area from homes, schools, hospitals, nursing homes, and other sensitive locations. The proposed regulation would also require pollution controls for existing wells and facilities within the same 3,200-foot setback area. CalGEM is currently in the process of conducting an economic analysis of the proposed rule. Following this analysis, CalGEM will submit a proposed rule to the Office of Administrative Law and will begin an additional process of receiving formal comments and refinement of the proposal as needed before a final rule can be issued. We continue to assess the impacts of this rule, and we currently anticipate that approximately 29% of our acreage could be impacted by the setback requirements if finalized as proposed.

In February 2021, California State Senators Scott Wiener and Monique Limón introduced Senate Bill 467, which proposes to halt the issuance or renewal of permits for hydraulic fracturing, acid well stimulation treatments, cyclic steaming, and water and steam flooding starting January 1, 2022, and then prohibit these extraction methods entirely starting January 1, 2027. SB 467 also would have prohibited all new or renewed permits for oil and gas extraction within 2,500 feet of any homes, schools, healthcare facilities or long-term care institutions such as dormitories or prisons, by January 1, 2022. However, SB 467 never made it out of committee and other bills to limit well stimulation treatments have also previously been introduced and failed to pass through the California legislature. Although these legislative efforts have failed, it is possible that SB 467 or similar legislation could be reintroduced in the future and we cannot predict the results of such future efforts. While currently none of our California operations rely on hydraulic fracturing stimulation they do rely on other methods of well stimulation and injection, including cyclic steaming and water and steam flooding. 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, which could adversely affect our revenues, results of operations and net cash provided by operating activities. For additional information on regulatory and legislative risks in California that could adversely impact our operations. See “Items 1 and 2. Business and Properties—Regulation of Health, Safety and Environmental Matters.”

The onset of the COVID-19 pandemic significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the onset of the pandemic resulted in widespread travel restrictions, business closures and other restrictions that led to a significant reduction in demand for oil, NGL and gas, resulting in oil prices declining significantly beginning in the first quarter or 2020. In response to the reduced demand for, and prices of, crude oil, we reduced our 2020 planned capital expenditures by more than 50%, which negatively impacted production for that year.

While demand for and prices for oil, NGLs and gas generally improved during 2021 and into 2022 as travel restrictions, business closures and other restrictions were lifted, an increase in infections or the onset of a new variant of the virus could again reduce demand for and prices of oil, NGLs and gas. Persistently weak or additional declines in commodity prices could adversely affect the economics of our existing wells and planned future wells,

Our operations also may be adversely affected if significant portions of our workforce - and that of our customers and suppliers - are unable to work effectively, because of illnesses, quarantines, government actions, or other restrictions in connection with the pandemic. Although we managed the transition to temporary work from home arrangements and subsequent office re-openings without a significant loss in business continuity, we incurred additional costs and experienced some inefficiencies during the year as a result. If the ongoing outbreak were to worsen, and additional restrictions are implemented, certain operational and other business processes could slow which may result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies, any of which could adversely affect our operating results for as long as the current pandemic persists and potentially for some time after the pandemic subsides.

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. The outbreak of COVID-19 followed by certain actions taken by OPEC+ caused crude oil prices to decline significantly beginning in the first quarter of 2020, and prices remained below pre-pandemic levels for a prolonged period before they recovered. If oil prices were to significantly decline again 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:

•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 (e.g., global health epidemics such as the recent COVID-19 pandemic);

•the actions of OPEC and/or OPEC+;

•the price and quantity of imports of foreign oil and natural gas;

•political conditions, including embargoes, in or affecting other oil-producing activity;

•the level of global oil and natural gas exploration and production 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;

•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

Concerns over global economic conditions, energy costs, geopolitical issues, 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. Even as Brent pricing reached a historic low during the second quarter of 2020, we also experienced an adverse widening in the price differential between Brent and the California benchmark due to the lack of local demand and storage capacity. Although market conditions and the differential improved over the latter half of 2021, California pricing remained below pre-pandemic levels for a prolonged period.

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 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

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.

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; 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 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 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

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.

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 2022 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 18% of our steam capacity and approximately 65% 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 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

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 currently conduct operations in California near known wildfire and mudslide areas and earthquake fault zones. A future natural disaster, such as a fire, mudslide 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. 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 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 are not fully insured against all risks. Our oil and natural gas exploration and production 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 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

The loss of senior management or technical personnel could adversely affect 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.

Information technology 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. 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. 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. 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.

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. 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.

Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.

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 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 2022 capital expenditure budget of approximately $125 to $135 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. 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 2022 capital expenditures with cash flows from our operations, supplemented by cash on hand which was built as excess Levered Free Cash Flow during 2020 and 2021; however, our cash flows from operations, and access to capital should such cash flows and cash on hand prove inadequate, are subject to a number of variables, including:

•the volume of hydrocarbons we are able to produce from existing wells;

•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 RBL Facility;

•and our ability to access the capital markets.

If our revenues or the borrowing base under the 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 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.”

Although inflation in the United States has been relatively low in recent years, it rose significantly in the second half of 2021. This is believed to be the result of the economic impact from the COVID-19 pandemic, including the global supply chain disruptions and the government stimulus packages, among other factors. Global, industry-wide supply chain disruptions caused by the COVID-19 pandemic have resulted in shortages in labor, materials and services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could continue to cause costs to increase as well as scarcity of certain products and raw materials. We are experiencing some inflationary pressure for certain costs, including employees and vendors, although such cost increases did not materially impact our 2021 financial condition or results of operations, and we currently do not expect them to materially impact our 2022 financial results or operations. However, to the extent elevated inflation remains, we may experience further cost increases for our operations, including natural gas purchases and oilfield services 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.

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 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,

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.

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 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 (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.

As of December 31, 2021, we have hedged gas purchases at the following approximate volumes and prices: 34.9 mmbtu/d at $3.29 per mmbtu in 2022.

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.

The RBL 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;

•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 RBL Facility 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 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 RBL Facility.We, the administrative agent and lenders, each may request one additional redetermination

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, 2021, 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. Our ability to make scheduled payments on or to refinance our debt obligations, including the RBL 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 RBL 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.

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.

Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

Amounts drawn under the RBL Facility may bear interest rates in relation to LIBOR, depending on our selection of repayment options. On July 27, 2017, the Financial Conduct Authority in the U.K. announced that it would phase out LIBOR as a benchmark by the end of 2021. If LIBOR ceases to exist, we may need to renegotiate the RBL Facility and may not be able to do so with terms that are favorable to us. The overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR.

We have significant concentrations of credit risk with the purchasers of our oil and natural gas. For the year ended December 31, 2021, sales to Tesoro Refining and Marketing, PBF Holding, Kern Oil & Refining, and Phillips 66accounted for approximately 30%, 16%, 14%, and 12% 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

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

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.

California, where most of our assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations and our operations are subject to numerous and stringent state, local and other laws and regulations that could delay or otherwise adversely impact our operations. The jurisdiction, duties and enforcement authority of various state agencies have significantly increased with respect to oil and natural gas activities in recent years, and these state agencies as well as certain cities and counties have significantly revised their regulations, regulatory interpretations and data collection and reporting requirements and have indicated plans to issue additional regulations of certain oil and natural gas activities in 2022. Moreover, 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. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects.

In California, We are also increasingly impacted by policies designed to curtail the production and use of fossil fuels. For example, in September 2020, Governor Gavin Newsom of California issued an executive order that seeks to reduce both the supply of and demand for fossil fuels in the state. The executive order 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

Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities imposed under the Endangered Species Act or similar state laws designed to protect various wildlife, such as the Greater Sage Grouse. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. Permanent restrictions imposed to protect threatened or endangered species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.

Our customers, including refineries and utilities, and the businesses that transport our products to customers are also highly regulated. For example, federal and state agencies have subjected or, proposed subjecting, more gas and liquid gathering lines, pipelines and storage facilities to regulations that have increased business costs and otherwise affect the demand, volatility and other aspects of the price we pay for fuel gas. Certain municipalities have enacted restrictions on the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect the retail natural gas market for our utility customers and the demand and prices we receive for the natural gas we produce.

Costs of compliance may increase, and operational delays or restrictions may occur as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations, each of which has occurred in the past. For example, our costs have recently begun to increase due to new fluid injection regulations, data requirements for permitting, and idle well decommissioning regulations. For instance, in 2021 we paid $19 million in asset retirement obligations, an increase from $18 million in 2020, largely due to the new idle well regulations and EH&S focused costs and initiatives associated with developing existing fields. In addition, we may experience delays, as we have in the past, due to insufficient internal processes and personnel resource constraints at regulatory agencies that impede their ability to process permits in a timely manner that aligns with our production projects.

Government authorities and other organizations continue to study health, safety and environmental aspects of oil and natural gas operations, including those related to air, soil and water quality, ground movement or seismicity and natural resources. Government authorities have also adopted, proposed, or otherwise considering new or more stringent requirements for permitting, well construction and public disclosure or environmental review of, or restrictions on, oil and natural gas operations. For example, there has been increased scrutiny with respect to hydraulic fracturing over the years by various state and federal agencies, which scrutiny has extended to oil and gas exploration and production activities more generally. This has resulted in more stringent regulation with respect to air emissions from oil and gas operations, restrictions on water discharges and calls to remove exemptions for certain oil and gas wastes from federal hazardous waste laws and regulations, amongst other restrictions. Separately, as another example, the scope of the federal Clean Water Act (“CWA”) has been subject to substantial uncertainty in recent years, which has the potential to increase permitting burdens. In 2015, the EPA and the U.S. Army Corps of Engineers (“Corps”) issued a rule expanding the scope of the term “Waters of the United States” (“WOTUS”) to include certain areas not traditionally considered to be subject to federal jurisdiction (the “Clean Water Rule”). Subsequently, in January 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrowed the definition of jurisdictional WOTUS relative to the Clean Water Rule. Both of these rulemakings have been subject to legal challenge, and the Biden Administration has announced plans to establish its own definition of

Changes to elected or appointed officials or their priorities and policies could result in different approaches to the regulation of the oil and natural gas industry. We cannot predict the actions the California governor or legislature may take with respect to the regulation of our business, the oil and natural gas industry or the state's economic, fiscal or environmental policies, nor can we predict what actions may be taken in states or at the federal level with respect to environmental laws and policies, including those that may directly or indirectly impact 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.

In past years, federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to natural gas and oil exploration and development companies. For example, the Biden administration has set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to, (i) an increase in the U.S. income tax rate applicable to corporations and (ii) the elimination of tax subsidies, generally in the form of accelerated deductions, for fossil fuels. Congress could consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws could adversely affect our operations and cash flows.

Additionally, in California, there have been proposals for new taxes on profits that might have a negative impact on us. Although the proposals have not become law, campaigns by various special interest groups could lead to future additional oil and natural gas severance or other taxes. The imposition of such taxes could significantly reduce our profit margins and cash flow and otherwise significantly increase our costs.

Derivatives legislation and regulations could have an adverse effect on our ability to use derivative instruments to reduce the risks associated with our business.

The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the over-the-counter (“OTC”) derivatives market and entities, like us, that participate in that market. Rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may hold and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to, or otherwise be affected by, such regulations. Even though certain of the European Union implementing regulations have become effective, the ultimate effect on our business of the European Union implementing regulations (including future implementing rules and regulations) remains uncertain.

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 exploration and production activities, and reduce demand for the oil and natural gas we produce.

The threat of climate change 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 oil and natural gas exploration and production 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 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 DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into a law, a resolution to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would establish new source and first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirement, and reduction of emissions by 95% through capture and control systems. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

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 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 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 September 2018, California adopted a law committing California , the fifth largest economy in the world, to the use of 100% zero-carbon electricity by 2045, and the Governor of California also signed an executive order committing California to total economy-wide carbon neutrality by 2045. In furtherance of these goals, Governor Newsom issued an order to CalGEM in April 2021, directing the agency to initiate regulatory action to end the issuance of new permits for hydraulic fracturing by January 2024. Additionally, Governor Newsom requested that the CARB analyze pathways to phase out oil extraction across the state by no later than 2045. 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, following an executive order signed by President Biden on his first day in office, the United States rejoined the Paris Agreement in February 2021. In April 2021, the United States 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 the 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. 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 through 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 calls 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. The Biden Administration has also called for restrictions on leasing on federal land, including the Department of Interior’s publication of a report in November 2021 recommending various changes to the federal leasing program, though any such changes would require Congressional action; for more information, see our regulatory disclosure titled “Hydraulic Stimulation”. Our operations involve the use of hydraulic fracturing activities and we also have operations on federal lands under the jurisdiction of the BLM within the DOI. 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 cities and other local governments 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. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effects of these actions, such limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the Securities and Exchange Commission announced its intention to promulgate rules requiring climate disclosures.

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. Moreover, there are increasing risks to operations resulting from the potential physical impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

A large portion of our common stock is beneficially owned by a relatively small number of stockholders. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures, hostile takeovers or other transactions, including the payment of dividends or the issuance of additional equity or debt, that, in their judgment, could enhance their investment in us or in another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations.

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.

Our governing documents provide that our stockholders and their affiliates are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, the Certificate of Incorporation, among other things:

•permits stockholders to make investments in competing businesses; and

•provides that if one of our directors who is also an employee, officer or director of a stockholder (a “Dual Role Person”), becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Our director who is a Dual Role Person may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which our stockholders have invested, in which case we may not become aware of, or otherwise have the ability to pursue, such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to be unavailable to us or causing them to be more expensive for us to pursue.

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.

Certain of our largest stockholders were creditors of Berry LLC prior to the Chapter 11 Proceedings and we cannot predict when or whether they will sell their shares of common stock. Future sales, or concerns about them, may put downward pressure on the market price of our common stock

We may sell or otherwise issue additional shares of common stock or securities convertible into shares of our common stock. Our Certificate of Incorporation provides for authorized capital stock consisting of 750,000,000 shares of common stock and 250,000,000 shares of preferred stock. In addition, we registered shares of the great majority of our common stock for resale. For more information see Exhibit 4.4 to our Annual Report on Form 10-K.

The issuance of any securities for acquisitions, financing, upon conversion or exercise of convertible securities, or otherwise may result in a reduction of the book value and market price of our outstanding common stock. If we issue any such additional securities, the issuance will cause a reduction in the proportionate ownership and voting power of all current stockholders. We cannot predict the size of any future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Shares of our common stock are also reserved for issuance as equity-based awards to employees, directors and certain other persons under the second amended and restated 2017 Omnibus Incentive Plan (our “Omnibus Plan”). We have filed a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our Omnibus Plan. Subject to the satisfaction of vesting conditions, the expiration of certain lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction. Investors may experience dilution in the value of their investment upon the exercise of any equity awards that may be granted or issued pursuant to the Omnibus Plan in the future.

The payment of dividends will be at the discretion of our board of directors.

We temporarily discontinued our quarterly dividends in the second quarter 2020 following the historic oil price drop and economic impact of COVID-19. We reinstated a quarterly dividend at a reduced rate beginning the first quarter of 2021 and then increased the rate 50% beginning with the third quarter of 2021. The Company's Board of Directors declared a regular dividend of $0.06 per share on the Company’s outstanding common stock, payable on April 15, 2022 to shareholders of record at the close of business on March 15, 2022. In addition, the Board implemented a shareholder return strategy that contemplates additional dividends to shareholders from discretionary cash flow, but there is no certainty that we will generate discretionary cash flow, nor is the Board obligated to make any dividends and any dividends are subject to the restrictions in our debt documents as described below. The payment and amount of future dividend payments, if any, are subject to declaration by our Board. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our Board deems relevant. Additionally, covenants contained in our RBL Facility and the indentures governing our 2026 Notes could limit the payment of dividends. We are under no obligation to make dividend payments on our common stock and cannot be certain when such payments may resume in the future.

We may issue preferred stock, the terms of which could adversely affect the voting power or value of our common stock.

Our Certificate of Incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

We are an “emerging growth company,” and are able to take advantage of reduced disclosure requirements applicable to “emerging growth companies,” which could make our common stock less attractive to investors.

We are an “emerging growth company” and, for as long as we continue to be an “emerging growth company,” we intend to take advantage of certain exemptions from various reporting requirements, including auditor attestation requirements or any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding a non-binding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We could be an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the first fiscal year in which our annual gross revenues exceed $1.07 billion, (ii) as of the end of the fiscal year that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common stock that is held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or (iii) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.

We intend to take advantage of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards which lasts until those standards apply to private companies or we no longer qualify as an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those companies who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable.

To the extent investors find our common stock less attractive as a result of our reduced reporting and exemptions, there may be a less active trading market for our common stock, and our stock price may be more volatile.

Our internal control over financial reporting is not currently required to meet all of the standards required by Section 404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and share price.

Section 404 of the Sarbanes-Oxley Act requires us to provide annual management assessments of the effectiveness of our internal control over financial reporting. However, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act until we are no longer an “emerging growth company,” which could be up to five years from our IPO.

Effective internal controls are necessary for us to provide reliable financial reports, safeguard our assets, and prevent fraud. If we cannot provide reliable financial reports, safeguard our assets or prevent fraud, our reputation and operating results could be harmed. The rules governing the standards that must be met for our management to assess our internal control over financial reporting are complex and require significant documentation, testing and possible remediation.

We may encounter problems or delays in completing the implementation of effective internal controls. Further, failure to achieve and maintain an effective internal control environment could have a material adverse effect on our business and share price and could limit our ability to report our financial results accurately and timely.

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 that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation and Bylaws may have the effect of delaying or preventing changes in control if our Board of Directors determines that such changes in control are not in the best interests of us and our stockholders. For more information see Exhibit 4.4 to our Annual Report on Form 10-K.

For example, our Certificate of Incorporation and Bylaws include provisions that (i) authorize our Board to issue “blank check” preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval and (ii) establish advance notice procedures for nominating directors or presenting matters at stockholder meetings.

These provisions could enable the Board to delay or prevent a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.

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, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders, (iii) any action asserting a claim against us, our directors, officers or employees arising pursuant to any provision of the Delaware General Corporation Law, our Certificate of Incorporation or our Bylaws or (iv) any action asserting a claim against us, our directors, officers or employees that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having subject matter jurisdiction and personal jurisdiction over the indispensable parties named as defendants therein. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.

None.

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

Securities Litigation Matter

On November, 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the Exchange Act, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.'s securities between July 26, 2018 and

On January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on January 24, 2022; plaintiffs’ opposition is due on March 21, 2022 and Defendants' reply is due on May 16, 2022.

We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the preliminary stage of the case, and the legal standards that must be met for, among other things, class certification and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this action.

Other Matters

For additional information regarding legal proceedings, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Commitments, and Contingencies” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations.”

Not applicable.

Part II

Our common stock has been trading on the NASDAQ under the ticker symbol “bry” since July 26, 2018. Prior to that there was no established public trading market for our common stock.

Our common stock was held by 31 stockholders of record at January 31, 2022.

We historically have, and plan to continue using our operating cash flows to cover our interest requirements, fund operations at sustained production levels, and routinely return meaningful capital to stockholders in the form of quarterly fixed dividends through commodity price cycles. .

We first began paying a quarterly dividend paying in our first quarter as a public company in 2018, which we paid regularly through the first quarter of 2020. We temporarily discontinued our quarterly dividends in the second quarter 2020 following the historic oil price drop and economic impact of COVID-19. We reinstated a quarterly dividend at a reduced rate beginning the first quarter of 2021 and then increased the rate 50% beginning with the third quarter of 2021. Our Board declared a regular dividend at a rate of $0.06 per share on the Company’s outstanding common stock, payable on April 15, 2022 to shareholders of record at the close of business on March 15, 2022.

In early 2022, we implemented a new shareholder return model, for which we intend to allocate a significant portion of discretionary free cash flow to cash variable dividends to be paid quarterly. We expect remaining cash flows will be allocated to fund opportunistic debt repurchases, opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. This new model is designed to significantly increase cash returns to our shareholders, further demonstrating Berry's commitment to be a leading returner of capital to its shareholders. Any dividends actually paid will be determined by our Board of Directors in light of existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors.

Securities Authorized for Issuance Under Equity Compensation Plans

On June 27, 2018, our Board approved our second amended and restated 2017 Omnibus Incentive Plan (the “Omnibus Plan”). A description of the plans can be found in Item 8. Financial Statements and Supplementary Data – Note 6–Equity. The aggregate number of shares of our common stock authorized for issuance under stock-based compensation plans for our employees and non-employee directors is 10 million, of which 8.6 million have been issued or reserved through December 31, 2021.

The following table summarizes information related to our equity compensation plans under which our equity securities are authorized for issuance as of December 31, 2021.

Plan Category

Number of Securities to be Issued Upon Exercise of Outstanding Options and Rights (#)(1)

Weighted-Average Exercise Price of Outstanding Options and Rights ($)

Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (#)(3)

Equity compensation plans not approved by security holders(2)

6,998,815

N/A

1,368,778

________________

(1)     The number of securities to be issued upon vesting of unvested restricted stock units (“RSUs”) subject to time vesting and performance-based restricted stock units (“PSUs”), assumes maximum achievement of certain market-based performance goals over a specified period of time. 

(2)     In connection with the IPO, our Board amended and restated the Company’s First Amended and Restated 2017 Omnibus Incentive Plan, which had amended and restated the Company’s 2017 Omnibus Incentive Plan (the “Prior Plans” and, collectively with the Omnibus Plan, the “Equity Compensation Plans”), which allowed us to grant equity-based compensation awards with respect to up to 10,000,000 shares of common stock (which number includes the number of shares of common stock previously issued pursuant to an award (or made subject to an award that has not expired or been terminated) under the Prior Plans), to employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Omnibus Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents and other types of awards. 

(3)     The number of securities remaining available for future issuances has been reduced by the number of securities to be issued upon settlement of RSUs subject to time vesting and PSUs assuming maximum achievement of certain market-based performance goals over a specified period of time. 

Sales of Unregistered Securities

None

In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at the time, they authorized repurchases of up to $50 million under the program. In 2018 and 2019, the Company repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million in aggregate. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million available under the repurchase program. We did not repurchase any common stock in 2020. For the year ended December 31, 2021, we repurchased 471,022 shares at an average price of $5.18 per share for approximately $2 million in the third quarter. All shares repurchased are reflected as treasury stock. Accordingly, as of December 31, 2021, the Company has repurchased a total of 5,528,704 shares under the stock repurchase program for approximately $52 million in aggregate, leaving approximately $48 million authorized and available for future repurchases under the program. The new shareholder return model that we implemented in January 2022 contemplates the potential use of a portion of discretionary free cash flow to opportunistically repurchase common stock.

Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes.

The following graph compares the cumulative total return to stockholders on our common stock relative to the cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S. Exploration and Production indexes and the Vanguard Energy ETF (with reinvestment of all dividends). The graph assumes that on July 26, 2018, the date our common stock began trading on the NASDAQ, $100 was invested in our common stock and in each index, and that all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future performance.

			7/26/18						12/18						06/19						12/19						06/20						12/20						06/21						12/21
Berry Corporation (bry)			$	100.00					$	67.17					$	83.16					$	75.90					$	40.66					$	30.98					$	57.25					$	72.98
S&P Smallcap 600			$	100.00					$	83.66					$	95.12					$	102.72					$	84.38					$	114.32					$	141.26					$	144.98
Dow Jones U.S. Exploration & Production			$	100.00					$	71.18					$	78.12					$	79.29					$	49.00					$	52.61					$	81.45					$	89.92
Vanguard Energy ETF			$	100.00					$	73.67					$	82.49					$	80.50					$	51.03					$	53.89					$	80.32					$	84.17

(1)    The performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing of the

Company under the Securities Act of 1933, as amended (the “Securities Act”) or the Exchange Act except to the extent that we specifically request it be treated as soliciting material or specifically incorporate it by reference.

(2)    $100 invested on July 26, 2018 in stock or June 30, 2018 in index, including reinvestment of dividends.

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes included elsewhere in this report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are described in “Item 1A. Risk Factors” included earlier in this report. Please see “—Cautionary Note Regarding Forward-:Looking Statements.”

This section of the Form 10-K generally discusses 2021 and 2020 items and year-to-year comparisons between those years. For discussion of our year ended December 31, 2019, as well as the year ended 2020 compared to year ended 2019, refer to Part II, Item 7— “Management's Discussion and Analysis of Financial Condition and Results of Operations” of our 2020 Annual Report on Form 10-K.

We are a western United States independent upstream energy company focused on the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California. As further discussed below, in the fourth quarter of 2021, we diversified our operations with the acquisition of a business with well servicing and abandonment capabilities. As of October 1, 2021, we have operated in two business segments: (i) development and production (“D&P”) (ii) well servicing and abandonment. The development and production segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which became a reportable segment (well servicing and abandonment) under U.S. GAAP.

Our upstream development and production assets, in the aggregate, are characterized by high oil content, with 100% oil content for our California assets, and are in rural areas with low population. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. For example, the cost to drill and complete the different types of our wells in California is approximately $400,000 per well. The vertical wells in Utah operations cost approximately $1.5 million per well. In contrast, wells in typical unconventional resource plays cost $5 million to $10 million to drill and complete. The California oil market has Brent-linked pricing which in recent history realizes premium pricing to WTI. In the past five years Brent pricing has averaged almost $5 above WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin, which has more than 150 years of production history and substantial oil remaining in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics are well understood, which enables predictable, repeatable, low geological risk and low-cost development opportunities. We also have upstream assets in the low-operating cost, oil-rich reservoirs in the Uinta basin of Utah. In January 2022, we divested our natural gas properties in the Piceance basin of Colorado.

In the fourth quarter of 2021, we acquired one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J Well Services. This acquisition creates a strategic growth opportunity for Berry. It 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, C&J Well Services 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. We believe that C&J Well Services is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as an orphan well), and there are approximately 35,000 idle wells estimated to be in California according to third-party sources.

Since our Initial Public Offering in 2018, we have demonstrated our commitment to returning a substantial amount of capital to shareholders, delivering $134 million to our shareholders through dividends and share repurchases through 2021. In 2022, we initiated a new shareholder return model, which is designed to significantly increase cash returns to our shareholders from our discretionary free cash flow, which we define as cash flow from operations less regular fixed dividends and the capital needed to hold production flat. Like our business model, this new shareholder returns model is simple and further demonstrates our commitment to return capital to our shareholders.

We believe that the successful execution of our strategy across our low-declining, oil-weighted production base coupled with extensive inventory of identified drilling locations with attractive full-cycle economics will support our objectives to generate Levered Free Cash Flow to fund our operations, optimize capital efficiency, and return meaningful capital to stockholders, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles.

As part of our commitment to creating long-term value for our stockholders, we are dedicated to conducting our operations in an ethical, safe and responsible manner, to protecting the environment, and to taking care of our people and the communities in which we live and operate.

How We Plan and Evaluate Operations

We use “Levered Free Cash Flow” in planning our capital allocation to sustain production levels and fund internal growth opportunities, as well as determine our strategic hedging needs (we also hedge to meet the hedging requirements of the 2021 RBL Facility). Levered Free Cash Flow is a non-GAAP financial measure that we define as Adjusted EBITDA less capital expenditures, interest expense and dividends. Adjusted EBITDA is also a non-GAAP financial measure that is discussed and defined below.

We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) shareholder returns; (c) operating expenses; (d) environmental, health & safety (“EH&S”) results; (e) general and administrative expenses; (f) production; and (g) well servicing and abandonment operations performance. With respect to our development and production business, we also measure oil and gas production levels. For our well services and abandonment business, we measure their performance through activity levels, pricing and relative performance for each service provided.

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business. Adjusted EBITDA is a non-GAAP financial measure that we define as earnings before interest expense; income taxes; depreciation, depletion, and amortization (“DD&A”); derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items.

Shareholder Returns

In early 2022, we implemented a new shareholder return model, for which we intend to allocate a significant portion of discretionary free cash flow to cash variable dividends to be paid quarterly. The model is based on our discretionary free cash flow, which is defined as cash flow from operations less regular fixed dividends and the capital needed to hold production flat. We expect remaining cash flows will be allocated to fund opportunistic debt repurchases, opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Our focus on shareholder returns is also demonstrated through our performance-based restricted stock awards, which are based on the Company's average cash returned on invested capital.

Operating Expenses

Overall, operating expense is used by management as a measure of the efficiency with which operations are performing. With respect to our production business, we define operating expenses as lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases. Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Taxes other than income taxes and costs of services are excluded from operating expenses. Marketing revenues represent sales of natural gas purchased from and sold to third parties. The electricity, transportation and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economics of development projects and the efficiency of our hydrocarbon recovery. Additionally, we strive to minimize the variability of our fuel gas costs for our California steam operations with gas hedges, and more recently agreements to transport fuel gas from the Rockies which have historically been cheaper than the California markets.

Environmental, Health & Safety

Like other companies in the oil and gas industry, both our production and well services operations are subject to complex and stringent federal, state and local laws and regulations relating to drilling, completion, well stimulation, well servicing, operation, maintenance or abandonment of wells or facilities, managing energy, water use, land use, managing greenhouse gases or other emissions, governing the discharge of materials into the environment or otherwise relating to environmental protection, including air quality, and the transportation, marketing, and sale of our products.

With respect to our production operations, current and future laws and regulations, as well as legislative and regulatory changes and other government activities, can materially impact our development, production, well servicing and abandonment plans, including by restricting the production rate of oil, natural gas and NGLs below the rate that would otherwise be possible. Additionally, the regulatory burden on the industry increases the cost of doing business and consequently effects capital expenditures and earnings.

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

We have a progressive approach to growing and evolving our businesses in today's dynamic oil and gas industry. Our strategy includes proactively engaging the many forces driving our industry and impacting our operations, whether positive or negative, to maximize the utility of our assets, create value for shareholders, and support environmental goals that align with safer, more efficient and lower emission operations. 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 monitor our EH&S performance through various measures, holding our employees and contractors to high standards. Meeting corporate EH&S metrics, including with respect to health and safety and spill prevention, is a part of our short-term incentive program for all employees.

General and Administrative Expenses

We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities and approximately 9% of such costs are capitalized, which is significantly less than industry norms. Such expenses are a key component of the appropriate level of support our corporate and professional team provides to the development of our assets and our day-to-day operations.

Production

Oil and gas production is a key driver of our operating performance, an important factor to the success of our business, and used in forecasting future development economics. We measure and closely monitor production on a continuous basis, adjusting our property development efforts in accordance with the results. We track production by commodity type and compare it to prior periods and expected results.

Well Servicing and Abandonment Operations Performance

We consistently monitor our well servicing and abandonment operations performance with revenue by service and customer, as well as Adjusted EBITDA for this business.

Our operating and financial results, and those of the oil and gas industry as a whole, are heavily influenced by commodity prices. Oil and gas prices and differentials have, and may continue to, fluctuate significantly as a result of numerous market-related variables, including global geopolitical and economic conditions. While oil prices have improved in 2021 and into 2022, they still remain volatile.

Our well services and abandonment business is dependent on expenditures of oil and gas companies, which can in part reflect the volatility of commodity prices. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells historically have been relatively stable and predictable. Additionally, our customers' requirements to plug and abandon wells is largely driven by regulatory requirements that is less dependent on commodity prices.

The recent recovery in the oil and gas industry has improved with increasing oil prices as demand increases with more states and countries re-opening and national and global economies continuing to recover from the global COVID-19 pandemic. The demand for oil, while improving as the ability of the global industry to grow supply diminishes, could again decline if there is a widespread resurgence of the COVID-19 outbreak. The extent to which our operating and financial results of future periods will be adversely impacted by the ongoing COVID-19 pandemic and the actions of foreign oil and gas producers will depend largely on future developments, which are highly uncertain and cannot be accurately predicted. Further, to what extent these events do ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors that are not within our control and cannot be predicted, including the duration and extent of the pandemic and speculation as to future actions by OPEC+. We were proactive in taking steps to address the challenges and mitigate repercussions from both the COVID-19 pandemic and industry downturns on our operations, our financial condition and our people.

As we focused on managing our business and operations in response to this health and economic crisis, the safety and well-being of our employees and the communities in which we operate remained our top priority. We are committed to being a good corporate citizen and demonstrated this commitment by focusing on the well-being of our employees and communities, including maintaining our strong safety and environmental standards and investing in community impact initiatives.

Because the visibility of the long-term supply and demand for oil has improved, we reinstated the quarterly dividend in the first quarter of 2021, which had been temporarily suspended in 2020, increased the dividend beginning the third quarter of 2021, and repurchased treasury shares during the year. Since our Initial Public Offering in 2018, we have demonstrated our commitment to returning a substantial amount of capital to shareholders, delivering $134 million to our shareholders through dividends and share repurchases through 2021. In 2022, we initiated a new shareholder return model, which is designed to significantly increase cash returns to our shareholders from our discretionary free cash flow, which we define as cash flow from operations less regular fixed dividends and the capital needed to hold production flat. Like our business model, this new shareholder returns model is simple and further demonstrates our commitment to return capital to our shareholders.

Commodity Pricing and Differentials

Our revenue, costs, profitability, shareholder returns and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as the prices we pay for our natural gas purchases, which are affected by a variety of factors, including those discussed in Part I, Item 1A. “Risk Factors” in this Annual Report.

Average oil prices were higher for the year ended December 31, 2021 compared to the year ended December 31, 2020. Brent crude oil contract prices ranged from $51.09 per bbl to $86.40 per bbl and averaged $70.95 per bbl during the year. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics.

In California, the price we have typically paid for fuel gas purchases is generally based on the Kern, Delivered Index, which was as high as $120.13 per mmbtu in February due to the effects of Winter Storm Uri, and as low as $2.37 per mmbtu during 2021, while we paid an average of $5.64 per mmbtu for the year.

The following table presents the average Brent, WTI, Kern Delivered, and Henry Hub prices for the years ended December 31, 2021 and 2020:

			Year Ended December 31,
			2021						2020
Brent oil ($/bbl)			$	70.95					$	43.21
WTI oil ($/bbl)			$	67.90					$	39.59
Kern, Delivered natural gas ($/mmbtu)			$	5.65					$	2.46
Henry Hub natural gas ($/mmbtu)			$	3.89					$	2.03

As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 65% to 70% of the state’s demand from OPEC+ countries and other waterborne sources. Without the higher costs and potential environmental impact associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing, in appropriate oil price environments, should continue to allow us to realize positive cash margins in California over the cycle.

Utah oil prices have historically traded at a discount to WTI as the local refineries are designed for Utah's unique oil characteristics and the remoteness of the assets makes access to other markets logistically challenging. However, we have high operational control of our existing acreage, which provides significant upside for additional vertical and or horizontal development and recompletions.

Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in the Rockies. Natural gas prices were strong in 2021 and we expect will continue to exhibit strength in 2022 based on current and projected supply and demand balances. In recent history, the California gas markets have generally had higher gas prices than the Rockies and the rest of the United States. Higher gas prices have a negative impact on our operating results. However, we mitigate a portion of this exposure by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. We also strive to minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of such gas purchases. In addition, we recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that help limit our exposure to fuel gas purchase price fluctuations. Additionally, the negative impact of higher gas prices on our California operating expenses is partially offset by higher gas sales for the gas we produce and sell in the Rockies.

Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the

Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by two of our cogeneration facilities under long-term contracts with terms ending in July 2022 through December 2026. The most significant input and cost of the cogeneration facilities is natural gas. We generally receive significantly more revenue from these cogeneration facilities in the summer months, most notably in June through September, due to negotiated capacity payments we receive. In October 2021 we sold Placerita, which included a cogeneration facility requiring significant fuel gas purchases, and generated significant amount of electricity throughout the year, especially in the summer months.

Seasonal weather conditions can impact our drilling, production and well servicing activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling and completion objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may have been and in the future may be impacted by ice and snow in the winter, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as by wild fires and rain.

Additionally, like other companies in the oil and gas industry, our operations are subject to stringent federal, state and local laws and regulations relating to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing, and sale of our products. 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. For more information related to regulatory risks, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry”.

The following tables set forth information regarding average daily production, total production, and average prices for the years ended December 31, 2021 and 2020.

			Year Ended December 31,
			2021						2020
Average daily production:(1)
Oil (mbbl/d)			24.2						25.0
Natural Gas (mmcf/d)			17.1						18.5
NGLs (mbbl/d)			0.4						0.4
Total (mboe/d)(2)			27.4						28.5
Total Production:
Oil (mbbl)			8,825						9,176
Natural gas (mmcf)			6,224						6,766
NGLs (mbbl)			141						131
Total (mboe)(2)			10,004						10,435
Weighted-average realized prices:
Oil without hedges ($/bbl)			$	66.57					$	39.56
Effects of scheduled derivative settlements ($/bbl)			$	(16.45)					$	16.51
Oil with hedges ($/bbl)			$	50.12					$	56.07
Natural gas ($/mcf)			$	5.27					$	2.08
NGLs ($/bbl)			$	36.64					$	12.57
Average Benchmark prices:
Oil (bbl) – Brent