UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 001-36478
California Resources Corporation
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction of |
incorporation or organization)
|(I.R.S. Employer |
27200 Tourney Road, Suite 200
Santa Clarita, California 91355
(Address of principal executive offices) (Zip Code)
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
|Title of Each Class||Trading Symbol(s)||Name of Each Exchange on Which Registered|
|Common Stock||CRC||New York Stock Exchange|
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 Date File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period as 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 the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
|Large Accelerated Filer||☐||Accelerated Filer||☐||Non-Accelerated Filer||☑|
|Smaller Reporting Company||☑||Emerging Growth Company||☐|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑
State 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, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30, 2020: $59 million.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑ No ☐
At February 28, 2021, there were 83,319,660 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement to be filed within 120 days after December 31, 2020 with the Securities and Exchange Commission in connection with the registrant's 2021 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
|Part I|| |
|Items 1 & 2|
BUSINESS AND PROPERTIES
Business Overview and History
Production, Price and Cost History
Estimated Proved Reserves, Future Net Cash Flows and Drilling Locations
Regulation of the Oil and Natural Gas Industry
UNRESOLVED STAFF COMMENTS
MINE SAFETY DISCLOSURES
|Part II|| || |
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
SELECTED FINANCIAL DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Basis of Presentation
Production and Prices
Divestitures and Acquisitions
Statement of Operations Analysis
Liquidity and Capital Resources
Lawsuits, Claims, Commitments and Contingencies
Critical Accounting Policies and Estimates
Significant Accounting and Disclosure Changes
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Quarterly Financial Data (Unaudited)
Supplemental Oil and Gas Information (Unaudited)
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
|Part III|| || |
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
PRINCIPAL ACCOUNTANT FEES AND SERVICES
|Part IV|| |
ITEMS 1 & 2 BUSINESS AND PROPERTIES
Business Overview and History
We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide ample, affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to making value-based capital investments. Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.
Our average net production was 111 thousand barrels of oil equivalent per day (MBoe/d) for the year ended December 31, 2020. We have the largest privately held mineral acreage position in the state, consisting of approximately 2.1 million net mineral acres spanning four of California’s major oil and natural gas basins. As of December 31, 2020, our proved reserves totaled an estimated 442 million barrels of oil equivalent (MMBoe), of which 313 million barrels (MMBbl) were crude oil and condensate reserves, 41 MMBbl were NGL reserves and 527 billion cubic feet (BcF), or 88 MMBoe, were natural gas reserves. We convert natural gas volumes to crude oil equivalents using a ratio of six thousand cubic feet (Mcf) to one barrel of crude oil equivalent based on energy content. This is a widely used conversion method in the oil and gas industry.
Reorganization Under Chapter 11 and Emergence from Bankruptcy Proceedings and Subsequent Refinancing
A severe industry downturn and commodity price collapse caused by the global Coronavirus Disease 2019 (COVID-19) pandemic and the over-supply resulting from a price war between members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia and other allied producing countries led us to file voluntary petitions for relief under a Chapter 11 proceeding on July 15, 2020 (Chapter 11 Cases) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court).
We emerged from bankruptcy on October 27, 2020 with a new board of directors, new equity owners and a significantly improved financial position. Under the plan of reorganization approved by the Bankruptcy Court (the Plan), all of our outstanding pre-emergence indebtedness under our credit facilities and senior notes was cancelled. At emergence, we entered into a new revolving credit facility with a $1.2 billion borrowing base and $540 million of lender commitments (Revolving Credit Facility). Our post-emergence capital structure also included a $200 million second lien term loan (Second Lien Term Loan), and $300 million of secured notes due 2027 issued by our wholly-owned subsidiary in connection with our acquisition of our partner's interest in our Elk Hills Power joint venture (EHP Notes).
On January 20, 2021, we completed an offering of $600 million aggregate principal amount of 7.125% senior notes due 2026 (Senior Notes). We used the net proceeds to repay in full our Second Lien Term Loan and EHP Notes, with the remainder of the net proceeds used to repay a portion of the outstanding borrowings under our Revolving Credit Facility.
For information on the significant transactions which occurred upon our emergence from Chapter 11, see Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Basis of Presentation and Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings. For more information on our debt, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt.
Board of Directors
On October 27, 2020, all but one of our existing directors resigned and seven new non-employee directors were appointed to our Board of Directors (Board) in connection with our emergence from bankruptcy. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our Board and, thus, have different views on the issues that will determine our strategic direction. In addition, our former Chief Executive Officer and director Todd A. Stevens departed on December 31, 2020. Our Board is led by Mark A. (Mac) McFarland, our Chairman and interim Chief Executive Officer, and James N. Chapman, our Lead Independent Director.
The Board has initiated a search process for our next Chief Executive Officer and a strategic review of our business. As a result of this review, we have streamlined our organization and are repositioning ourselves as a low-cost operator. We intend to pursue asset divestitures to focus our operations on core fields that we expect will further lower our costs and enhance free cash flow.
Fresh Start Accounting
We adopted fresh start accounting in connection with our emergence from bankruptcy because (1) the holders of existing voting shares prior to emergence received less than 50% of our new voting shares following our emergence and (2) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than our post-petition liabilities and allowed claims. Reorganization value represents the fair value of our total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring.
Under fresh start accounting, the reorganized entity is considered a new reporting entity for financial reporting purposes. As a result, the reorganization value of the emerging entity is assigned to individual assets and liabilities based on their estimated relative fair values. The reorganization value was derived from our enterprise value, which was the estimated fair value of our long-term debt and shareholder’s equity at emergence from bankruptcy. In support of the Plan, our enterprise value was estimated and approved by the Bankruptcy Court to be in the range of $2.2 billion to $2.8 billion. Based on our internal estimates and assumptions, we estimated our enterprise value to be $2.5 billion, at about the mid-point of the range approved by the Bankruptcy Court. For additional information on the effects of fresh start accounting, see Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Basis of Presentation and Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting.
Fresh start accounting was applied as of October 31, 2020, an accounting convenience date, to coincide with the timing our normal month-end close process. We evaluated and concluded that transactions between October 28, 2020 and October 31, 2020 were not material and the use of an accounting convenience date was appropriate. As such, fresh start accounting was reflected in our consolidated balance sheet as of October 31, 2020. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. References to "Predecessor” refer to the Company for periods ending on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.
Under the leadership of our new Board appointed in October 2020, we have implemented a business strategy with the following key priorities:
•Deliver value and drive free cash flow generation. With a right-sized balance sheet, a leaner organization and a lower cost base, we believe we are well positioned to compete across a wide range of potential commodity price environments. Our asset base – with its low decline rates and efficient capital requirements – provides significant advantages. Our capital program is designed to be funded from operating cash flow and improved margins. We intend to focus on crude oil projects, thus over time improving our margins. We believe this operating model, coupled with premium pricing on our products, as compared to U.S. benchmarks, position us as a leading exploration and production (E&P) company to deliver operationally and financially.
•Maintain our commitment to safety and sustainability and show leadership on environmental, social and governance (ESG) practices in the E&P space. We are focused on our ESG performance while improving overall corporate transparency and highlighting the positive impact we have on communities in which we operate. Our 2030 Sustainability Goals and our ongoing sustainability strategy are intended to align with the climate goals of California, which has committed to adhere to the Paris Agreement, which entered into force on November 4, 2016 (the Paris Agreement). We publish a sustainability report annually that documents our proven track record of safety, technological innovation and operational excellence and dedication to our ESG policies. As part of this strategy, our 2020 compensation metrics for our management team included specific ESG targets for safety, environmental stewardship and sustainability project milestones.
•Maintain dynamic capital allocation process to drive cash flow generation across a range of commodity price environments. In the current Brent oil price environment, a substantial portion of our expected capital expenditures will be allocated to oil driven workover and shallow drilling, which we expect to generate strong margins and cash flow with short nominal payback. If Brent oil prices decrease, we retain the flexibility to reduce capital spending, while benefiting from the downside protection from our hedges, in order to preserve free cash flow. If Brent oil prices increase, we would consider incremental investment to further enhance value and increase long-term free cash flow generation.
•Continue to pursue a predictable, advantaged and integrated asset base. Our diverse, lower-decline and lower-risk production portfolio in prolific conventional basins with a high net revenue interest provides a higher level of predictability. Our integrated and owned infrastructure assets further enhance margins and provide operational control. Our asset characteristics and integrated operations exemplify our strategy of maintaining low business and execution risk. Our operations are further advantaged by our location in California, a leading economy within the United States. The deficit in California’s energy supply, combined with the local infrastructure and transportation systems constraints, provides premium realizations on all of our products as compared to U.S. benchmarks.
•Maintain operational excellence while reducing our cost structure. We expect to further improve our performance and execution by continuing to lower operating costs and increase drilling, completion and related facilities capital efficiencies. We reduced our operating expenses to an average of $55 million per month in the fourth quarter of 2020. We have retooled our organization for the current commodity price environment as we have steadily reduced general and administrative (G&A) expenses from approximately $300 million in 2019 to approximately $250 million in the twelve months ended December 31, 2020.
•Preserve balance sheet strength with a disciplined approach to capital allocation and a robust hedging program. Our capital allocation priorities are guided by our focus on maximizing the value of our assets while protecting our balance sheet, maintaining mechanical integrity of our infrastructure and maintaining or, in a higher commodity price environment, growing our base production while generating free cash flow. We target a capital budget that is funded from expected cash flows. As part of this strategy, we typically utilize a combination of derivative instruments to protect our cash flows. We intend to maintain low leverage going forward. Additionally, we are targeting a net debt to adjusted EBITDAX ratio of less than 1.5x and are committed to maintaining a strong liquidity position.
We have the largest privately held mineral acreage position in California, consisting of approximately 2.1 million net mineral acres spanning four of California's major oil and natural gas basins. Our operated asset base spans 130 distinct fields with approximately 12,000 operated wells. Our average net production of approximately 111 MBoe/d (62% oil) for the year ended December 31, 2020. Our average net revenue interest was approximately 87% as of December 31, 2020. The following table highlights key information about our operations as of and for the year ended December 31, 2020:
|San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total Operations|
Net mineral acreage (thousands)
|1,347 ||30 ||225 ||503 ||2,105 |
|Average net mineral acreage held in fee (%)||73 ||%||47 ||%||81 ||%||37 ||%||65 ||%|
|Number of fields||44 ||6 ||27 ||53 ||130 |
Average net revenue interest (%)(a)
|90 ||%||80 ||%||89 ||%||80 ||%||87 ||%|
Average drilling rigs(b)
|2 ||— ||— ||— ||2 |
Net wells drilled and completed(b)
|4.0 ||4.5 ||— ||0.4 ||8.9 |
|Oil (MMBbl)||199 ||104 ||10 ||— ||313 |
|NGLs (MMBbl)||40 ||— ||1 ||— ||41 |
|Natural gas (Bcf)||468 ||7 ||7 ||45 ||527 |
|Total (MMBoe)||317 ||105 ||12 ||8 ||442 |
|Oil percentage of proved reserves||63 ||%||99 ||%||83 ||%||— ||%||71 ||%|
|Total net production (MMBoe)||29 ||9 ||1 ||1 ||40 |
|Average daily net production (MBoe/d)||79 ||24 ||4 ||4 ||111 |
|Oil percentage of net production||53 ||%||100 ||%||75 ||%||— ||%||62 ||%|
Reserves to production ratio (years)(c)
|10.9 ||11.7 ||12.0 ||8.0 ||11.1 |
Note: MMBbl refers to millions of barrels; Bcf refers to billions of cubic feet; MMBoe refers to millions of barrels of oil equivalent; and MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(a)The average net revenue interest represents our interest in production after considering royalties and similar burdens and third-party working interests.
(b)Beginning in March 2020, as a result of the low commodity price environment, we reduced our operating costs and planned capital expenditures to those necessary to maintain mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner. We also decreased the number of drilling rigs we then operated throughout the state to zero.
(c)Calculated as total proved reserves as of December 31, 2020 divided by total production for the year ended December 31, 2020.
San Joaquin Basin
The San Joaquin basin contains some of the largest oil fields in the United States based on cumulative production and proved reserves. Commercial petroleum development in the basin began in the 1800s. The basin contains multiple stacked formations throughout its areal extent, and we believe that the San Joaquin basin provides appealing opportunities for field re-development of existing wells, as well as new discoveries and unconventional play potential. The geology of the San Joaquin basin continues to yield stratigraphic and structural trap discoveries. Approximately 75% of California’s total daily oil production for 2018 was produced in the San Joaquin basin, according to CalGEM.
We hold substantially all the working, surface and mineral interests in the Elk Hills field, which is our largest producing asset in the San Joaquin Basin and one of the largest fields in the continental U.S.
At Elk Hills we also operate efficient natural gas processing facilities, including a state-of-the-art cryogenic gas plant, with a combined gas processing capacity of over 520 MMcf/d. Additionally, our Elk Hills power plant generates sufficient electricity to operate the field, and sells excess power to the wholesale market and a utility. Our operations at Elk Hills also include an advanced central control facility and remote automation control on over 95% of the producing wells.
We have a large ownership interest in several of the largest existing oil fields in the San Joaquin basin including Buena Vista and Coles Levee. We have also been successfully developing steamfloods in our Kern Front operations.
We believe our extensive 3D seismic library, which covers approximately 800,000 acres in the San Joaquin basin, or approximately 50% of our gross mineral acreage in this basin, gives us a competitive advantage in field development and further exploration.
Los Angeles Basin
This basin is a northwest-trending plain about 50 miles long and 20 miles wide. Most of the significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has one of the highest concentrations per acre of crude oil in the world. The basin contains multiple stacked formations throughout its depths, and we believe that the Los Angeles basin provides a considerable inventory of existing field re-development opportunities as well as new play discovery potential. Large active oil fields include the Wilmington and Huntington Beach fields, where we have significant operations.
The Wilmington field has been one of the largest fields in the continental U.S. Most of our Wilmington production is subject to a set of contracts similar to production-sharing contracts (PSCs) under which we first recover the capital and operating costs we incur on behalf of the state and the city of Long Beach and then receive our share of profits.
The Ventura Basin is the oldest operating oil basin in California extending from northern Los Angeles County to the coastal area of Ventura. The earliest discoveries were mines dug into hillsides to mine active oil seeps. The first commercial oil well started in 1866. The entire sedimentary section is productive at various locations, and most reservoirs are sandstones with favorable porosity and permeability. As of December 31, 2020, we operated more than 20 oil fields in this historic and prolific basin. The basin contains multiple stacked formations and provides an appealing inventory of existing field re-development opportunities, as well as new exploration potential.
The Sacramento basin is a deep, thick sequence of sedimentary deposits of natural gas within an elongated northwest-trending structural feature covering about 7.7 million acres. Exploration and development in the basin began in 1918. Our significant mineral acreage position in the Sacramento basin gives us the option for future development and rapid production growth in an attractive natural gas price environment.
The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2020.
|San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total|
| ||(in thousands)|
| || || || || |
|438 ||21 ||60 ||265 ||784 |
|398 ||16 ||58 ||245 ||717 |
| || || || || |
|1,171 ||17 ||201 ||317 ||1,706 |
|949 ||14 ||167 ||258 ||1,388 |
|1,609 ||38 ||261 ||582 ||2,490 |
|1,347 ||30 ||225 ||503 ||2,105 |
(a)Mineral acres spaced or assigned to productive wells.
(b)Total number of mineral acres in which interests are owned.
(c)Net mineral acreage includes acreage reduced to our fractional ownership interest and interests under PSC-type contracts.
(d)Mineral 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 mineral acreage contains proved reserves.
Approximately 65% of our total net mineral interest position is held in fee and the remainder is leased. Of our leased acreage, approximately 49% is held by production and the remainder is subject to lease expiration if initial wells are not drilled within a specified period of time. The primary terms of our leases range from one to ten years. The terms of these leases are typically extended upon achieving commercial production for so long as such production is maintained. Work programs are designed to ensure that the economic potential of any leased property is evaluated before expiration. In some instances, we may relinquish leased acreage in advance of the contractual expiration date if the evaluation process is complete and there is no longer a commercial reason for leasing that acreage. In cases where we determine we want to take the additional time required to fully evaluate undeveloped acreage, we have generally been successful in obtaining extensions.
Approximately 58,000 net mineral acres will expire in 2021, 119,000 net mineral acres will expire in 2022 and 57,000 net mineral acres will expire in 2023 if production is not established and we take no other action to extend the terms of the leases. These leases expiring in the next three years represented 17% of our total net undeveloped acreage at December 31, 2020 and these expirations, should they occur, would not have a material adverse impact on us. Historically, we have not dedicated any significant portion of our capital program to prevent lease expirations and do not expect we will need to do so in the future.
Production, Price and Cost History
The following table sets forth information regarding our production, average realized and benchmark prices and operating costs per Boe for the years ended December 31, 2020, 2019 and 2018. For additional information on production and prices, see information set forth in Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production and Prices.
| ||November 1, 2020 - December 31, 2020||January 1, 2020 - October 31, 2020||Year Ended December 31, 2020||Year Ended December 31, 2019||Year Ended December 31, 2018|
|Average daily production|| || || |
|Oil (MBbl/d)||63 ||70 ||69 ||80 ||82 |
|NGLs (MBbl/d)||12 ||13 ||13 ||15 ||16 |
|Natural gas (MMcf/d)||165 ||174 ||172 ||197 ||202 |
Total daily production (MBoe/d)(a)(b)
|103 ||112 ||111 ||128 ||132 |
Total production (MMBoe)(a)(b)
|6 ||34 ||40 ||47 ||48 |
|Average realized prices|| || || |
|Oil with hedge ($/Bbl)||$||45.37 ||$||43.19 ||$||43.53 ||$||68.65 ||$||62.60 |
|Oil without hedge ($/Bbl)||$||45.65 ||$||41.21 ||$||41.89 ||$||64.83 ||$||70.11 |
|NGLs ($/Bbl)||$||38.00 ||$||25.70 ||$||27.63 ||$||31.71 ||$||43.67 |
|Natural gas without hedge ($/Mcf)||$||3.21 ||$||2.11 ||$||2.28 ||$||2.87 ||$||3.00 |
|Average benchmark prices|| || || |
|Brent oil ($/Bbl)||$||47.10 ||$||42.43 ||$||43.21 ||$||64.18 ||$||71.53 |
|WTI oil ($/Bbl)||$||44.21 ||$||38.44 ||$||39.40 ||$||57.03 ||$||64.77 |
|NYMEX gas ($/MMBtu)||$||2.86 ||$||1.95 ||$||2.10 ||$||2.67 ||$||2.97 |
Operating costs per Boe(b)
| || || |
|Operating costs||$||18.19 ||$||14.95 ||$||15.45 ||$||19.16 ||$||18.88 |
Operating costs, excluding effects of PSC-type contracts(c)
|$||16.86 ||$||14.14 ||$||14.56 ||$||17.70 ||$||17.47 |
Note: Bbl refers to barrels; MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MMBtu refers to millions of British Thermal Units.
(a)We temporarily shut in production of 3 MBoe/d in 2020, which negatively impacted our production compared to 2019. Additionally, our divestiture of a 50% working interest in certain zones within our Lost Hills field resulted in a decrease of approximately 2 MBoe/d beginning in the second quarter of 2019. Our PSC-type contract positively impacted our oil production in 2020 by approximately 3 MBoe/d compared to 2019. PSC-type contracts had no impact on our oil production in 2019 compared to 2018.
(b)Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas (Mcf) to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(c)The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. These amounts represent operating costs after adjusting for the excess costs attributable to PSC-type contracts.
Oil, natural gas and NGL production for our two largest fields are presented in the table below:
| ||Elk Hills||Wilmington|
|Average daily production|| || || || || || |
|Oil (MBbl/d)||18||22 ||22 ||21 ||20 ||21 |
|NGLs (MBbl/d)||10||12 ||12 ||— ||— ||— |
|Natural gas (MMcf/d)||90||103 ||108 ||1 ||1 ||1 |
|Total daily production (MBoe/d)||43||51 ||52 ||21 ||20 ||21 |
Oil, NGLs and natural gas are commodities, and the prices we receive for our production are largely a function of market supply and demand. Product prices are affected by a variety of factors, including changes in domestic and global supply and demand; domestic and global inventory levels; political and economic conditions; the actions of OPEC and other significant producers and governments; changes or disruptions in actual or anticipated production, refining and processing; worldwide drilling and exploration activities; government energy policies and regulations, including with respect to climate change; the effects of conservation; weather conditions and other seasonal impacts; speculative trading in derivative contracts; currency exchange rates; technological advances; transportation and storage capacity, bottlenecks and costs in producing areas; the price, availability and acceptance of alternative energy sources; regional market conditions and other matters affecting the supply and demand dynamics for these products, along with market perceptions with respect to all of these factors. We have a hedging program to help protect our cash flow, operating margin and capital program, while maintaining adequate liquidity.
Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. The measures taken to address the recent industry downturn demonstrate that we can significantly reduce our operating costs in response to prevailing market conditions. We further believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs in a safe and responsible manner throughout their lifecycles.
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to PSC-type contracts that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production, and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher. These PSC-type contracts represented 18% of our production for the year ended December 31, 2020.
In addition, in line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in operating costs on our consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts. This difference in reporting full operating costs but only our net share of production equally inflates our revenue and operating costs per barrel and has no effect on our net results.
Estimated Proved Reserves, Future Net Cash Flows and Drilling Locations
The information with respect to our estimated reserves presented below has been prepared in accordance with the rules and regulations of the United States Securities and Exchange Commission (SEC).
The following tables summarize our estimated proved oil (including condensate), NGLs and natural gas reserves and PV-10 as of December 31, 2020. Our estimated volumes and cash flows were calculated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year (SEC Prices), unless prices were defined by contractual arrangements. For oil volumes, the average Brent spot price of $41.77 per barrel was adjusted for gravity, quality and transportation costs. For natural gas volumes, the average NYMEX gas price of $1.98 per MMBtu was adjusted for energy content, transportation fees and market differentials. All prices are held constant throughout the lives of the properties. The average realized prices for estimating our proved reserves as of December 31, 2020 were $42.35 per barrel for oil, $26.42 per barrel for NGLs and $2.28 per Mcf for natural gas.
Estimated reserves include our economic interests under arrangements similar to PSCs at our Wilmington field in Long Beach. Refer to Part II, Item 8 – Financial Statements, Supplemental Oil and Gas Information for additional information on our proved reserves.
| ||As of December 31, 2020|
| ||San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total|
|Proved developed reserves|| || || || || |
|Oil (MMBbl)||171 ||85 ||10 ||— ||266 |
|NGLs (MMBbl)||38 ||— ||1 ||— ||39 |
|Natural Gas (Bcf)||413 ||6 ||7 ||34 ||460 |
|278 ||86 ||12 ||6 ||382 |
|Proved undeveloped reserves|| || || || || |
|Oil (MMBbl)||28 ||19 ||— ||— ||47 |
|NGLs (MMBbl)||2 ||— ||— ||— ||2 |
|Natural Gas (Bcf)||55 ||1 ||— ||11 ||67 |
|39 ||19 ||— ||2 ||60 |
|Total proved reserves|| || || || || |
|Oil (MMBbl)||199 ||104 ||10 ||— ||313 |
|NGLs (MMBbl)||40 ||— ||1 ||— ||41 |
|Natural Gas (Bcf)||468 ||7 ||7 ||45 ||527 |
|317 ||105 ||12 ||8 ||442 |
(a)As of December 31, 2020, approximately 27% of proved developed oil reserves, 13% of proved developed NGLs reserves, 16% of proved developed natural gas reserves and, overall, 24% of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full production response has not yet occurred due to the nature of such projects.
(b)Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
Changes to Proved Reserves
There were material changes to our December 31, 2020 reserve estimates when compared to our December 31, 2019 reserve estimates due to factors including (i) price-related revisions, (ii) performance-related revisions and (iii) booking of certain proved undeveloped reserves as part of fresh start accounting which were previously written off under the SEC’s five year rule.
The components of the changes to our proved reserves during the year ended December 31, 2020 were as follows:
| ||San Joaquin Basin|
Los Angeles Basin(a)
|Ventura Basin||Sacramento Basin||Total|
|Balance at December 31, 2019||417 ||170 ||42 ||15 ||644 |
|Revisions related to price||(38)||(20)||(14)||— ||(72)|
|Revisions related to performance||(23)||(19)||(14)||(5)||(61)|
|Removal of proved undeveloped reserves||(27)||(23)||(1)||(1)||(52)|
|Extensions and discoveries||19 ||6 ||— ||— ||25 |
|Divestitures||(2)||— ||— ||— ||(2)|
|Balance at December 31, 2020||317 ||105 ||12 ||8 ||442 |
Note: Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(a)Includes proved reserves related to PSC-type contracts of 85 MMBoe and 125 MMBoe at December 31, 2020 and 2019, respectively.
Price-related revisions – We had negative price-related revisions of 72 MMBoe primarily resulting from a lower commodity price environment in 2020 compared to 2019. The net price revision reflects the shortened economic lives of our fields, as estimated using 2020 SEC pricing, which for oil was significantly lower than current oil prices, partially offset by our lower operating costs.
Performance-related revisions – We had 61 MMBoe of net negative performance-related revisions which included negative performance-related revisions of 73 MMBoe and positive performance-related revisions of 12 MMBoe. Our negative performance-related revisions primarily related to wells that underperformed their forecasts. A significant factor for this underperformance was a reduction in our capital program in 2020 due to the low commodity price environment and constraints during our bankruptcy process. This led to higher overall decline rates due to injection curtailments, capacity limitations and reduced well maintenance. Our positive performance-related revisions of 12 MMBoe primarily related to better-than-expected well performance.
Removal of proved undeveloped reserves – We removed 52 MMBoe of proved undeveloped reserves, all of which were no longer included in our development plans because they did not meet internal investment thresholds at lower SEC prices. The majority of these revisions were located in the San Joaquin and Los Angeles basins.
Extensions and discoveries – We added 25 MMBoe from extensions and discoveries, approximately half of which resulted from the booking of proved undeveloped reserves in connection with fresh start accounting. Successful drilling and workovers in the San Joaquin and Los Angeles basins also contributed to the increase.
Proved Undeveloped Reserves
The total changes to our proved undeveloped reserves during the year ended December 31, 2020 were as follows:
| ||San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total|
|Balance at December 31, 2019||88 ||47 ||13 ||3 ||151 |
|Revisions related to price||(14)||(8)||(6)||— ||(28)|
|Revisions related to performance ||(13)||(3)||(6)||— ||(22)|
|Removal of proved undeveloped reserves||(27)||(23)||(1)||(1)||(52)|
|Extensions and discoveries||17 ||6 ||— ||— ||23 |
|Improved recovery||— ||— ||— ||— ||— |
|Divestitures||— ||— ||— ||— ||— |
|Transfers to proved developed reserves||(12)||— ||— ||— ||(12)|
|Balance at December 31, 2020||39 ||19 ||— ||2 ||60 |
Note: Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
Price-related revisions – We had negative price-related revisions of 28 MMBoe primarily resulting from a lower commodity price environment in 2020 compared to 2019.
Performance-related revisions – We had 22 MMBoe of net negative performance-related revisions. As a result of underperformance of certain producing wells, proved undeveloped projects were revised downward by 24 MMBoe. The performance of producing wells can impact undeveloped projects in several ways such as estimation of analogous type curves, constraining infrastructure capacity and field curtailment due to economic limits. A significant factor was a reduction in our capital program due to the low commodity price environment and constraints during the bankruptcy process. This led to a steepening of base decline due to injection curtailment, capacity limitations and reduced well maintenance. We also added 2 MMBoe primarily related to better-than-expected performance.
Removal of proved undeveloped reserves – We removed a total of 52 MMBoe of proved undeveloped reserves, all of which were no longer prioritized in our development plans because they did not meet internal investment thresholds at lower SEC prices. The majority of these revisions are located in the San Joaquin and Los Angeles basins.
Extensions and discoveries – We added 23 MMBoe of proved undeveloped reserves through extensions and discoveries, approximately half of which resulted from the booking of proved undeveloped reserves in connection with fresh start accounting. The remainder of additions resulted from a very limited drilling program concentrated on deeper wells in the San Joaquin basin and our low cost capital workover program in our shallow waterflood fields resulted in favorable results.
Transfers to proved developed reserves – We converted 12 MMBoe of proved undeveloped reserves to proved developed reserves in the San Joaquin basin. This resulted in a conversion rate of approximately 8% of our beginning-of-year proved undeveloped reserves, with an investment of approximately $10 million of drilling and completion capital, to the proved developed category.
Our year-end development plans and associated proved undeveloped reserves are consistent with SEC guidelines for development within five years. We believe we will have sufficient capital to develop all year-end 2020 proved undeveloped reserves within five years.
PV-10, Standardized Measure and Reserve Replacement Ratio
PV-10 of cash flows is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC Prices. Calculation of PV-10 does not give effect to derivative transactions. Our PV-10 is computed on the same basis as our standardized measures of future net cash flows, the most comparable measure under GAAP, but does not include the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.
|As of December 31, 2020|
|Standardized measure of discounted future net cash flows||$||1,932 |
|Present value of future income taxes discounted at 10%||494 |
PV-10 of cash flows(a)
(a)The average realized prices for estimating our PV-10 of cash flow as of December 31, 2020 were $42.35 per barrel for oil, $26.42 per barrel for NGLs and $2.28 per Mcf for natural gas.
Reserves Evaluation and Review Process
Our estimates of proved reserves and associated discounted future net cash flows as of December 31, 2020 were made by our technical personnel, comprised of reservoir engineers and geoscientists, with the assistance of operational and financial personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and management's funding commitments to develop the reserves. Reserves volumes are estimated by forecasts of production rates, operating costs and capital investments. Price differentials between specified benchmark prices and realized prices and specifics of each operating agreement are then applied against the SEC Price to estimate the net reserves. Production rate forecasts are derived using a number of methods, including estimates from decline-curve analysis, type-curve analysis, material balance calculations, which consider the volumes of substances replacing the volumes produced and associated reservoir pressure changes, seismic analysis and computer simulations of reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formations being evaluated or in analogous formations. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities related to the proved reserves.
Proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods, for which the incremental cost of any additional required investment is relatively minor. Proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.
Our Vice President, Reserves and Corporate Development has primary responsibility for overseeing the preparation of our reserves estimates. She has 20 years of experience as an energy sector engineer including as a Senior Reservoir Engineer with Ryder Scott Company, L.P. (Ryder Scott). She is a member of the Society of Petroleum Engineers (SPE) for which she served as past chair of the U.S. Registration Committee. She holds a Master of Business Administration from the Massachusetts Institute of Technology, a Master of Engineering in Petroleum Engineering from the University of Houston and a Bachelor of Science from the University of Florida. She is also a registered Professional Engineer in the state of Texas.
We have an Oil and Gas Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, which reviewed and approved our oil and natural gas reserves for 2020. The Reserves Committee annually reports its findings to the Audit Committee.
Audits of Reserves Estimates
Ryder Scott and Netherland, Sewell & Associates, Inc. (NSAI) were engaged to provide independent audits of our reserves estimates for our fields. For the year ended December 31, 2020, Ryder Scott audited 53% of our total proved reserves. NSAI audited 31% of our total proved reserves. Over 95% of our total 2020 proved reserves were audited by independent auditors at some time during the four-year period ended December 31, 2020.
Our independent reserve engineers examined the assumptions underlying our reserves estimates, adequacy and quality of our work product, and estimates of future production rates, net revenues, and the present value of such net revenues. They also examined the appropriateness of the methodologies employed to estimate our reserves as well as their categorization, using the definitions set forth by the SEC, and found them to be appropriate. As part of their process, they developed their own independent estimates of reserves for those fields that they audited. When compared on a field-by-field basis, some of our estimates were greater and some were less than the estimates of our independent reserve engineers. Given the inherent uncertainties and judgments in estimating proved reserves, differences between our estimates and those of our independent reserve engineers are to be expected. The aggregate difference between our estimates and those of the independent reserve engineers was less than 10%, which was within the SPE acceptable tolerance.
In the conduct of the reserves audits, our independent reserve engineers did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, crude oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if anything came to the attention of our independent auditors that brought into question the validity or sufficiency of any such information or data, they would not rely on such information or data until it had resolved its questions relating thereto or had independently verified such information or data. Our independent reserve engineers determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC as well as the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions. Both of our independent reserve engineers issued an unqualified audit opinion on the applicable portions of our proved reserves as of December 31, 2020, which are attached as Exhibit 99.1 and 99.2, respectively, to this Form 10-K and incorporated herein by reference.
Ryder Scott qualifications – The primary technical engineer responsible for our audit has more than 40 years of petroleum engineering experience, the majority of which has been in the estimation and evaluation of reserves. He serves on the Ryder Scott Board of Directors and is a registered Professional Engineer in the state of Texas.
NSAI qualifications – The primary technical engineer primarily responsible for our audit has 20 years of petroleum engineering experience, with the majority spent evaluating California properties, and is a registered Professional Engineer in the state of Texas.
The table below sets forth our total gross identified proved drilling locations by basin as of December 31, 2020, excluding injection wells.
| ||Proved Drilling Locations|
|San Joaquin Basin||451 |
|Los Angeles Basin||128 |
|Ventura Basin||— |
|Sacramento Basin||12 |
|Total Proved Drilling Locations||591 |
Based on our reserves report as of December 31, 2020, we have 591 gross drilling locations attributable to our proved undeveloped reserves. We use production data and experience gained from our development programs to identify and prioritize this proven drilling inventory. These drilling locations are included in our reserves only after we have adopted a development plan to drill them within a five-year time frame of the original reserve booking. As a result of rigorous technical evaluation of geologic and engineering data, we can estimate with reasonable certainty
that reserves from these locations will be commercially recoverable in accordance with SEC guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local regulations and other factors it deems relevant in determining such locations.
The following table sets forth information on our net exploration and development wells drilled and completed during the periods indicated, regardless of when drilling was initiated. 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. We refer to gross wells as the total number of wells in which interests are owned. Net wells represent wells reduced to our fractional interest.
|San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total Net Wells|
|2020|| || || || || |
|Productive|| || || || || |
|Exploratory||— ||— ||— ||— ||— |
|Development||4.0 ||4.5 ||— ||0.4 ||8.9 |
|2019|| || || || || |
|Productive|| || || || || |
|Exploratory||0.3 ||— ||— ||— ||0.3 |
|Development||117.5 ||25.2 ||2.0 ||2.4 ||147.1 |
|2018|| || || || || |
|Productive|| || || || || |
|Exploratory||0.3 ||— ||— ||— ||0.3 |
|Development||127.0 ||48.2 ||3.2 ||— ||178.4 |
|Exploratory||1.3 ||— ||0.3 ||— ||1.6 |
|Development||— ||— ||— ||— ||— |
We had one steamflood well, on a gross basis, which was pending completion in the San Joaquin basin as of December 31, 2020 and is not included in the table above.
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. Our average working interest in our producing wells is 88%. Wells are categorized based on the primary product they produce.
The following table sets forth our productive oil and natural gas wells (both producing and capable of production) as of December 31, 2020, excluding wells that have been idle for more than five years:
|As of December 31, 2020|
|Productive Oil |
|Productive Natural Gas Wells|
|San Joaquin Basin||8,099 ||7,113 ||152 ||148 |
|Los Angeles Basin||1,723 ||1,634 ||— ||— |
|Ventura Basin||755 ||743 ||— ||— |
|Sacramento Basin||— ||— ||828 ||761 |
|Total||10,577 ||9,490 ||980 ||909 |
|Multiple completion wells included in the total above||177 ||158 ||42 ||37 |
(a)The total number of wells in which interests are owned.
(b)Net wells include wells reduced to our fractional interest.
We have a robust prospect inventory of onshore conventional plays. California basins have generated billions of barrels of oil and trillions of cubic feet of natural gas and have established production from over 400 identified reservoir intervals in both structural and stratigraphic trap configurations, from depths of less than 1,000 feet to greater than 15,000 feet. Historical industry activity has focused on the primary and secondary development of known hydrocarbon accumulations, many of which were discovered over a century ago. We have a ranked near-field portfolio of over 150 exploration prospects across the San Joaquin, Sacramento and Ventura basins, as well as significant land positions in under-explored hydrocarbon reservoirs in each of California's four major oil and natural gas basins.
Our 3D seismic library covers approximately 4,950 square miles, representing approximately 90% of the 3D seismic data available in California, along with 12,000 square miles of 2D data. We have developed unique, proprietary stratigraphic and structural models of the subsurface geology and hydrocarbon potential in each of the four basins in which we operate. We have successfully implemented various exploration, drilling, completion and enhanced recovery technologies to increase recoveries, growth and value from our portfolio.
We believe our employees are our most important asset and, guided by our core values, strive to provide a safe and healthy workplace. We provide development opportunities and financial rewards so that our employees are engaged and focusing on providing safe, affordable, abundant energy for the people of California.
As of the date of this report, we had approximately 1,000 employees, all in the United States. Approximately 60 of our employees are covered by a collective bargaining agreement. We also utilize the services of many third party contractors throughout our operations.
We believe our core values of Character, Responsibility and Commitment and our comprehensive business and ethical conduct policies sustain and enhance shareholder value.
Our comprehensive business and ethical conduct policies apply to all directors, officers and employees, each of whom personally commits to following our code of conduct and our corporate policies, as well as to suppliers and vendors working in our operations. Our position is that no business goal is worth our employees compromising their integrity or our shared values.
Safe and Healthy Workplace
Our unwavering commitment to health, safety and the environment permeates all of our operations. Each year, we set a threshold injury and illness incidence rate as a quantitative metric that directly impacts incentive compensation for all of our employees. We have achieved exemplary, steadily improved safety performance over the last several years by promoting a culture of safety where all employees, contractors and vendors are empowered with Stop Work authority to cease any activity – without repercussions – to prevent a safety or environmental accident.
We promote the health and well-being of our employees by providing comprehensive health benefits and time off for illness and vacation.
Employee development opportunities are provided to enhance leadership development and expand career opportunities. A copy of our policies were provided to all employees, who also undergo mandatory annual training on the policies. Employer sponsored training reinforces our company-wide commitment to operate in accordance with all applicable laws, rules and regulations and to sustain a diverse and empowered workforce comprising our employees and those of our suppliers, vendors and joint ventures.
We provide our employees industry competitive base wages and incentive compensation opportunities, as well as comprehensive health and retirement benefits; life, disability and accident insurance coverages; and employee assistance and wellness programs to promote financial stability and healthy lifestyles.
We survey our employees annually to assess engagement levels and drivers to determine areas to focus on going forward. The results of the engagement surveys are reviewed by senior management and the Board.
During the course of the Chapter 11 Cases, we evaluated the structure of our workforce and implemented organizational changes in August 2020 that resulted in a reduction of our headcount from 1,250 to approximately 1,100 employees. Subsequent to our emergence from bankruptcy, we took steps to further align our cost structure to focus on our core assets and on becoming a low-cost operator. We reduced the size of our management team in January 2021 and then realigned several functions, which resulted in additional headcount and cost reductions. During the first quarter of 2021, we reduced our headcount to approximately 1,000 employees. We believe the steps taken improved and strengthened our business after we emerged from bankruptcy. In addition, on December 31, 2020, our former Chief Executive Officer and director Todd A. Stevens departed and Mark A. (Mac) McFarland was appointed our Interim Chief Executive Officer.
These personnel-related changes are expected to reduce the compensation expense component of our 2021 operating expenses by approximately $15 million per year and general and administrative expenses by approximately $50 million per year from our 2020 levels.
Crude Oil – We sell nearly all of our crude oil into the California refining markets, which offer favorable pricing for comparable grades relative to other U.S. regions. Substantially all of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.
Although California state policies actively promote and subsidize renewable energy, the demand for oil and natural gas in California remains strong. California is heavily reliant on imported sources of energy, with approximately 70% of oil and 90% of natural gas consumed in 2019 imported from outside the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices. We believe that the limited crude transportation infrastructure from other parts of the U.S. into California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades.
Natural Gas – We sell all of our natural gas not used in our operations into the California markets on a daily basis at average monthly index pricing. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity in the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada. As a result, we typically enjoy higher netback pricing relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas. Changes in natural gas prices have a smaller impact on our operating results than changes in oil prices as only approximately 25% of our total equivalent production volume and even a smaller percentage of our revenue is from natural gas.
In addition to selling natural gas, we also use natural gas in steam generation for our steamfloods and power generation. As a result, the positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to net higher revenue. Conversely, lower natural gas prices lower the operating costs but have a net negative effect on our financial results.
We currently have transportation capacity contracts to transport all of our natural gas volumes for the next three years. We sell virtually all of our natural gas production under individually negotiated contracts using market-based pricing.
NGLs – NGL price realizations are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints and seasonality can magnify price volatility.
Our earnings are also affected by the performance of our complementary natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.
We currently have a pipeline transportation contract for 6,500 barrels per day of NGLs. Our contract to transport NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually shipped. We have thus far met all our shipping commitments under this contract. In connection with another pipeline delivery contract that we assumed from Occidental, we made a one-time deficiency payment of $20 million in April 2020 when the contract expired. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately 30% of our NGLs are sold to export markets.
Electricity – Part of the electrical output of the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces field operating costs and provides a reliable source of power. We sell the excess electricity generated to a local utility, other third parties and the grid. The power sold to the utility is subject to agreements through the end of 2023, which include a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. Any excess capacity not sold to other third parties is sold to the wholesale power market. The prices obtained for excess power impact our earnings but generally by an relatively small amount.
We have short-term commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2020, we had oil delivery commitments of 41 MBbl/d through March 2021, NGL delivery commitments of 11 MBbl/d through April 2021 and natural gas delivery commitments of 32 MMcf/d through the end of 2021. We generally have significantly more production than the amounts committed for delivery and have the ability to secure additional volumes of products as needed. These are index-based contracts with prices set at the time of delivery.
Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. In addition, our Revolving Credit Facility requires us to maintain hedges on a minimum amount of crude oil production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred upon emergence from bankruptcy, and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date. The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.
We must also maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24 months following the date of delivery of each reserve report. We may not hedge more than 80% of reasonably anticipated total forecasted production of crude oil, natural gas and natural gas liquids from our oil and gas properties for a 48-month period.
Refer to Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources for current commodity contracts.
Our Principal Customers
We sell crude oil, natural gas and NGLs to marketers, California refineries and other purchasers that have access to transportation and storage facilities. Our ability to sell our products can be affected by factors that are beyond our control and cannot be accurately predicted.
We had three customers that individually accounted for at least 10%, and collectively accounted for 53%, of our sales (before the effects of hedging) during 2020. These purchasers are in the crude oil refining industry. In light of the ongoing energy deficit in California and the strong demand for native crude oil production, we do not believe that the loss of any single customer would have a material adverse effect on our financial condition or results of operations.
Title to Properties
As is customary in the oil and natural gas industry for acquired properties, we initially conduct a high-level review of the title to our properties at the time of acquisition. Individual properties may be subject to ordinary course burdens that we believe do not materially interfere with the use or affect the value of such properties. Burdens on properties may include customary royalty or net profits interests, liens incident to operating agreements and tax obligations or duties under applicable laws, or development and abandonment obligations, among other items. Prior to the commencement of drilling operations on those properties, we typically conduct a more thorough title examination and may perform curative work with respect to significant defects. We generally will not commence drilling operations on a property until we have cured known title defects that are material to the project. For additional information on properties which secure our debt, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Debt.
We encounter strong competition from numerous parties in the oil and natural gas industry doing business in California, ranging from small independent producers to major international oil companies. The oil market in California is a captive market with no interstate crude pipelines and only limited rail access and unloading capacity for refineries. California imports approximately 70% of the oil it consumes and virtually all of that arrives from waterborne sources. Our proximity to the California refineries gives us a competitive advantage through lower transportation costs. Further, California refineries are generally designed to process crude with similar characteristics to the oil produced from our fields. The California natural gas market is serviced from a network of pipelines, including interstate and intrastate pipelines. We deliver our natural gas to customers using our firm capacity contracts.
We compete for third-party services to profitably develop our assets, to find or acquire additional reserves, to sell our production and to find and retain qualified personnel. Higher commodity prices could intensify competition for drilling and workover rigs, pipe, other oil field equipment and personnel. However, the California energy industry has experienced only limited cost inflation in recent years due to excess capacity in the service and supply sectors. At current commodity price levels, we expect limited cost inflation in 2021. Further, our relative size and activity levels, compared to other in-state producers, favorably influences the pricing we receive from third-party providers in the markets in which we operate.
We also face indirect competition from alternative energy sources, including wind and solar power. Competitive conditions could be affected by future legislation and regulation as California continues to develop renewable energy and implements climate-related policies.
We own or control a network of strategically placed infrastructure that integrates with and complements our operations to maximize the value generated from our production. The significant scale of our integrated infrastructure helps us connect to third-party transportation pipelines, providing us with a competitive advantage by reducing our operating costs. We maintain a rigorous maintenance program, extending the life of our infrastructure and targeting safety and environmental stewardship. Our infrastructure includes the following:
|San Joaquin Basin||Other Basins||Total|
|Gas Processing Plants||8||MMcf/d||525||40||565|
|Water Management Systems||MBw/d||1,900||2,055||3,955|
|Oil and NGL Storage||MBbls||408||271||679|
(a)MW refers to megawatts of power; MBbl/d refers to thousand barrels of steam per day; MHp refers to thousand horsepower; MBw/d refers to thousand barrels of water per day; MBbl refers to thousands of barrels.
Natural Gas Processing
We believe we own or control the largest gas processing system in California. In the San Joaquin basin, the Elk Hills cryogenic gas plant has a capacity of 200 MMcf/d of inlet gas, bringing our total processing capacity in the basin to over 525 MMcf/d, which includes our two low temperature separation plants used as backup facilities. We also own and operate a system of natural gas processing facilities in the Ventura basin that are capable of processing our equity and third-party wellhead gas from the surrounding areas. Our natural gas processing facilities are interconnected via pipelines to nearby third-party rail and trucking facilities, with access to various North American NGL markets. In addition, we have truck rack facilities coupled with a battery of pressurized storage tanks at our natural gas processing facilities for NGL sales to third parties.
Our 550-megawatt combined-cycle Elk Hills power plant, located adjacent to the Elk Hills natural gas processing facility, typically generates all the electricity needed by our Elk Hills field and certain contiguous operations in the San Joaquin basin. We utilize approximately a third of its capacity for our operations and our subsidiary sells the excess to the grid and to a local utility. The Elk Hills power plant also provides primary steam supply to our cryogenic gas plant. We also operate intermittently a 45-megawatt cogeneration facility at Elk Hills that provides additional flexibility and reliability to support field operations. Within our Long Beach operations in the Los Angeles basin, we operate a 48-megawatt power generating facility that provides over 40% of our Long Beach operation’s electricity requirements. All of these facilities are integrated with our operations to improve their reliability and performance while reducing operating costs.
Water and Steam Infrastructure
We own, control and operate water management and steam-generation infrastructure, including steam generators, steam plants, steam distribution systems, steam injection lines and headers, water softeners and water processing systems. We soften and self-supply water to generate steam, reducing our operating costs. This infrastructure is integral to our operations in the San Joaquin basin and supports our high-margin oil fields such as Kern Front.
We own an extensive network of over 8,000 miles of oil and natural gas gathering lines. These gathering lines are dedicated almost entirely to collecting our oil and natural gas production and are in close proximity to field-specific facilities such as tank settings or central processing sites. These lines connect our producing wells and facilities to gathering networks, natural gas collection and compression systems, and water and steam processing, injection and distribution systems. Our oil gathering systems connect to multiple third-party transportation pipelines, which increases our flexibility to ship to various parties. In addition, virtually all of our natural gas facilities connect with major third-party natural gas pipeline systems. As a result of these connections, we typically have the ability to access multiple delivery points to improve the prices we obtain for our oil and natural gas production.
Oil and NGL Storage
Our tank storage capacity throughout California gives us flexibility for a period of time to store crude oil and NGLs, allowing us to continue production and avoid or delay any field shutdowns in the event of temporary power, pipeline or other shutdowns.
Regulation of the Oil and Natural Gas Industry
Our operations are subject to a wide range of federal, state and local laws and regulations. Those that specifically relate to oil and natural gas exploration and production are described in this section.
Regulation of Exploration and Production
Federal, state and local laws and regulations govern most aspects of exploration 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;
•improved or enhanced recovery techniques such as fluid injection for pressure management;
•sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and improved or enhanced recovery processes;
•imposition of taxes and fees with respect to our properties and operations;
•the conservation of oil and natural gas, including provisions for the unitization or pooling of oil and natural gas properties;
•posting of bonds or other financial assurance to drill, operate and abandon or decommission wells and facilities; and
•health, safety and environmental matters and the transportation, marketing and sale of our products as described below.
Collectively, the effect of these regulations is to potentially limit the number and location of our wells and the amount of oil and natural gas that we can produce from our wells compared to what we otherwise would be able to do.
CalGEM is California's primary regulator of the oil and natural gas industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. 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. Government actions, including the issuance of certain permits or approvals, by state and local agencies or by federal agencies may be subject to environmental reviews, respectively, under the California Environmental Quality Act (CEQA) or the National Environmental Policy Act (NEPA), which may result in delays, imposition of mitigation measures or litigation. CalGEM currently requires an operator to identify the manner in which CEQA has been satisfied prior to issuing various state permits, typically through either an environmental review or an exemption by a state or local agency. In Kern County this requirement has typically been satisfied by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015. A group of plaintiffs challenged the EIR and on February 25, 2020, a California Court of Appeal issued a ruling that invalidates a portion of the EIR until the County makes certain revisions to the EIR and recertifies it. On February 12, 2021, the Kern County Planning Commission voted to recommend approval of the revisions in a supplementary EIR in order to reestablish the county's oil and gas permitting system, though it must be approved by the county Board of Supervisors before becoming effective. This certification is expected to be completed in the first half of 2021; however, the supplemental EIR and certification may also be subject to litigation. After the supplementary EIR is certified, it is expected that CalGEM will rely on Kern County to serve as lead agent for CEQA purposes, reducing unnecessary delays at the state level.
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. For example, 2019 state legislation expanded CalGEM’s duties effective on January 1, 2020 to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs, and will require 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 which may be shared among operators. Other 2019 legislation specifically addressed oil and natural gas leasing by the State Lands Commission, including imposing conditions on assignment of state leases, requiring lessees to complete abandonment and decommissioning upon the termination of state leases, and prohibiting leasing or conveyance of state lands for new oil and natural gas infrastructure that would advance production on certain federal lands such as national monuments, parks, wilderness areas and wildlife refuges.
CalGEM and other state agencies have also significantly revised their regulations, regulatory interpretations and data collection and reporting requirements. CalGEM issued updated regulations in April 2019 governing management of idle wells and underground fluid injection, which include specific implementation periods. The updated idle well management regulations require operators 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. The updated underground injection regulations address injection approvals, project data requirements, testing of injection wells, monitoring and reporting requirements with respect to injection parameters, containment and incident response, among other topics. 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) review and updating of regulations regarding public health and safety near oil and natural gas operations pursuant to additional duties assigned to CalGEM by the Legislature in 2019; and (3) a performance audit of CalGEM's permitting processes for well stimulation treatment (WST) permits and project approval letters for underground injection (PALs) by the State Department of Finance and an independent review and approval 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, requires CalGEM to complete its public health and safety review and propose additional regulations, which are expected to be released for public comment in the spring of 2021 and to include expanded land use setbacks or buffer zones, and noted the Governor’s intent to seek legislation to end the issuance of new hydraulic fracturing permits by 2024. For more information, see Part I, Item 1A – Risk Factors. While the full impacts of this executive order cannot be predicted, additional state regulation of exploration and production activities could result in increased operating costs or delays in or the inability to obtain permits, or otherwise adversely affect production from the underlying properties.
The U.S. Environmental Protection Agency (EPA) and the BLM also regulate certain oil and gas activities. In January 2021, the Biden Administration issued orders temporarily suspending the issuance of new authorizations, and suspending the issuance of new leases (to the extent permitted by law) pending completion of a review of current practices, for oil and gas development on federal lands (the orders do not restrict such operations on tribal lands that the federal government merely holds in trust). Although the orders do 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 lands.
Federal and state pipeline regulations have also been recently revised. CalGEM imposed more stringent inspection and integrity management requirements in 2019 and 2020 with respect to certain natural gas pipelines in specified locations, with additional regulations anticipated in 2020 regarding digital mapping of such lines. The Office of the State Fire Marshal adopted regulations in 2020 to require risk assessment of various oil lines in the coastal zone, followed by retrofitting of certain of those lines with the best available control technology to mitigate oil spills over a specified implementation period. Finally, the federal Pipeline and Hazardous Materials Safety Administration issued new regulations in October 2019 expanding integrity management, leak detection and reporting requirements for liquid pipelines and natural gas transmission pipelines, with various implementation periods beginning in July 2020 and specific requirements dependent upon the characteristics of the line and its location.
In 2020, CalGEM commenced a series of public health and safety workshops to be followed by an associated rulemaking process that will consider various measures, including expanded land use setbacks or buffer zones. In February 2021, Senate Bill 467 (SB 467) was introduced. If passed, the bill would ban permits for hydraulic fracturing, acid well stimulation treatments, cyclic steaming, water flooding and steam flooding beginning in 2022 and would ban these activities entirely beginning in 2027. The bill would also allow local governments to prohibit such practices prior to 2027. After the bill was introduced one of the authors announced that it would also be amended to also add a 2,500 feet setback for new wells from sensitive receptors. We cannot predict the outcome of this most recent legislative effort. Previous high profile efforts to impose setbacks for new wells from sensitive receptors have failed; however, any restrictions on the use of well stimulation treatments or expanded setbacks could adversely impact our operations.
In addition, certain local governments have proposed or adopted ordinances that would restrict certain drilling activities in general and well stimulation, completion or injection activities in particular, impose setback distances from certain other land uses, or ban such activities outright. The most onerous of these local measures were adopted in 2016 by Monterey County, where we owned mineral rights but have no production and in 2020 by Ventura County, where we have both mineral rights and production. As written, the Monterey County measure sought to prohibit the drilling of new oil and natural gas wells, hydraulic fracturing and other well-stimulation techniques and to phase out the injection of produced water. This measure was challenged in state court and the Monterey County Superior Court issued a decision in 2017, finding that the bans on drilling new wells and water injection are preempted by and invalid under existing state and federal regulations and, if implemented, would constitute a taking of our property and that of other mineral rights owners without compensation. The court did not rule on the ban on hydraulic fracturing because the court found that the issue was not ripe since hydraulic fracturing is not currently being conducted in Monterey County, noting that the ban could be challenged in the event a project involving hydraulic fracturing is proposed. Although the County is complying with and declined to appeal the Court’s decision and settled the litigation, sponsors of the ballot measure have appealed.
In September 2020, the Ventura County Board of Supervisors (Ventura Board) adopted an amended General Plan and approved an associated EIR that impose significant restrictions on new discretionary development projects in Ventura County. With respect to new discretionary oil and gas development, the amended General Plan: requires setbacks of 1,500 feet and 2,500 feet from residences and schools, respectively; prohibits trucking of oil and produced water; restricts flaring; requires electrification of equipment; and requires additional reviews for projects involving WST or steam injection. Collectively, these restrictions would prevent or substantially reduce new development of at least five fields that we operate. In November 2020, the Ventura Board adopted ordinances to unilaterally revoke or revise longstanding conditional use permits, including permits held by us, thereby applying the amended General Plan to fields with existing permits, and to amend coastal and non-coastal specific plans to impose a 15-year time limit and other restrictions on new permits. Multiple lawsuits have been filed challenging the amended General Plan and EIR, including by us, on numerous statutory and constitutional grounds, and litigation is expected on the other ordinances as well.
Regulation of Health, Safety and Environmental Matters
Numerous federal, state, local and other laws and regulations that govern health and safety, the release or discharge of materials, land use or environmental protection may restrict the use of our properties and operations, increase our costs or lower demand for or restrict the use of our products and services. Applicable federal health, safety and environmental laws include the Occupational Safety and Health Act, Clean Air Act, Clean Water Act, Safe Drinking Water Act, Oil Pollution Act, Natural Gas Pipeline Safety Act, Pipeline Safety Improvement Act, Pipeline Safety, Regulatory Certainty, and Job Creation Act, Endangered Species Act, Migratory Bird Treaty Act, Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and NEPA, among others. California imposes additional laws that are analogous to, and often more stringent than, such federal laws. These laws and regulations:
•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;
•require various permits, approvals and mitigation measures before drilling, workover, production, underground fluid injection or waste disposal commences, or before facilities are constructed or put into operation;
•require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and shutdown 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, impose energy efficiency or renewable energy standards on us or users of our products and services, and restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics;
•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, or any other uses of those materials resulting from drilling, production, processing, power generation, transportation or storage activities;
•limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat and other protected areas, and require the dedication of surface acreage for habitat conservation;
•establish standards for the management of solid and hazardous wastes or the closure, abandonment, cleanup or restoration of former operations, such as plugging and abandonment of wells and decommissioning of facilities;
•impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment with respect to our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
•require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;
•impose taxes or fees with respect to the foregoing matters;
•may expose us to litigation with government authorities, counterparties, special interest groups or others; and
•may restrict our rate of oil, NGLs, natural gas and electricity production.
Due to the risk of future drought conditions in California, water districts and the state government have implemented regulations and policies that may restrict groundwater extraction and water usage and increase the cost of water. Water management, including our ability to recycle, reuse and dispose of produced water and our access to water supplies from third-party sources, in each case at a reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential component of our operations to produce crude oil, natural gas and NGLs economically and in commercial quantities. As such, any limitations or restrictions on wastewater disposal or water availability could have an adverse impact on our operations. We treat and reuse water that is co-produced with oil and natural gas for a substantial portion of our needs in activities such as pressure management, waterflooding, steamflooding and well drilling, completion and stimulation. We also provide reclaimed produced water to certain agricultural water districts. We also use supplied water from various local and regional sources, particularly for power plants and steam generation, and while our production to date has not been impacted by restrictions on access to third-party water sources, we cannot guarantee that there may not be restrictions in the future.
In 2014, at the request of the EPA, CalGEM commenced a detailed review of the multi-decade practice of permitting underground injection wells and associated aquifer exemptions under the SDWA. In 2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the SDWA in certain formations in certain fields. Since the state and the EPA did not complete their review before the state’s deadlines, the state announced that it will not rescind permits or enforce the deadlines with respect to many of the formations pending completion of the review but has applied the deadlines to others. Several industry groups and operators challenged CalGEM’s implementation of its aquifer exemption regulations. In March 2017, the Kern County Superior Court issued an injunction barring the blanket enforcement of CalGEM’s aquifer exemption regulations. The court found that CalGEM must find actual harm results from an injection well’s operations and go through a hearing process before the agency can issue fines or shut down operations. During the review, the state has restricted injection in certain formations or wells in several fields, including some operated by us, requested that we change injection zones in certain fields, and held certain pending injection permits in abeyance. We are coordinating with the state to change injection zones in certain fields to facilitate disposal of produced water in deeper formations where feasible or to increase recycling of produced water in pressure maintenance or waterfloods in lieu of disposal. As previously noted, the State Department of Finance is conducting a performance audit of CalGEM’s permitting process for injection projects, with an independent review of the technical content of pending injection PALs by Lawrence Livermore National Laboratory.
Separately, the state began a review in 2015 of permitted surface discharge of produced water and the use of reclaimed water for agricultural irrigation, which led to additional permitting and monitoring requirements in 2017 for surface discharge. To date, the foregoing regulatory actions have not affected our oil and natural gas operations in a material way. These reviews are ongoing, and government authorities may ultimately restrict injection of produced water or other fluids in additional formations or certain wells, restrict the surface discharge or use of produced water or take other administrative actions. The foregoing reviews could also give rise to litigation with government authorities and third parties.
Federal, state and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Regulation of Climate Change and Greenhouse Gas (GHG) Emissions
A number of international, federal, state, regional and local efforts seek to prevent or mitigate the effects of climate change or to track, mitigate and reduce GHG emissions associated with energy use and industrial activity, including operations of the oil and natural gas production sector and those who use our products as a source of energy or feedstocks. President Biden has announced that climate change will be a focus of his administration, and he has issued several executive orders on the subject, which, among other things, recommit the United States to the Paris Agreement, call for the reinstatement or issuance of methane emissions standards for new, modified and existing oil and gas facilities and call for an increased emphasis on climate-related risk across governmental agencies and economic sectors. Additionally, the EPA has adopted federal regulations to:
•require reporting of annual GHG emissions from oil and natural gas exploration and production, power plants and natural gas processing plants; gathering and boosting compression and pipeline facilities; and certain completions and workovers;
•incorporate measures to reduce GHG emissions in permits for certain facilities; and
•restrict GHG emissions from certain mobile sources.
California has adopted stringent laws and regulations to reduce GHG emissions. These state laws and regulations:
•established 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, the year that the cap-and-trade program currently expires;
•require allowances or qualifying offsets for GHGs emitted from California operations and for the volume of natural gas, propane and liquid transportation fuels sold for use in California;
•established a 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, and provide a mechanism to generate LCFS credits through innovative crude oil production methods such as those employing solar or wind energy or carbon capture and sequestration;
•mandated that California derive 60% of its electricity for retail customers from renewable resources by 2030;
•established a policy to derive all of California’s retail electricity from renewable or "zero-carbon" resources by 2045, subject to required evaluation of the feasibility by state agencies;
•imposed state goals to double the energy efficiency of buildings by 2030 and to reduce emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030; and
•mandated that all new single family and low–rise multifamily housing construction in California include rooftop solar systems or direct connection to a state–approved community solar system.
In addition, the current and former Governor of California and certain municipalities in California have announced their commitment to adhere to GHG reductions called for in the Paris Agreement through executive orders, pledges, resolutions and memoranda of understanding or other agreements with various other countries, U.S. states, Canadian provinces and municipalities. In furtherance of this commitment, in September 2020, the Governor of California issued an executive order directing several agencies to take further actions with respect to reducing emissions of GHGs. For more information, see Part I, Item 1A – Risk Factors.
The EPA and the California Air Resources Board (CARB) have also expanded direct regulation of methane as a contributor to GHG emissions. In 2016, the EPA adopted regulations to require additional emission controls for methane, volatile organic compounds and certain other substances for new or modified oil and natural gas facilities. Although the EPA rescinded the methane-specific requirements for production and processing facilities in September 2020, several lawsuits have been filed challenging these amendments, and the amendments may be subject to reversal under a new presidential administration. Moreover, CARB has implemented more stringent regulations that require monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and natural gas production, pipeline gathering and boosting facilities and natural gas processing plants, as well as additional controls such as tank vapor recovery to capture methane emissions.
Regulation of Transportation, Marketing and Sale of Our Products
Our sales prices of oil, NGLs and natural gas in the U.S. are set by the market and are not presently regulated. In 2015, the U.S. federal government lifted restrictions on the export of domestically produced oil that allows for the sale of U.S. oil production, including ours, in additional markets.
Federal and state laws regulate transportation rates for, and marketing and sale of, petroleum products and electricity with respect to certain of our operations and those of certain of our customers, suppliers and counterparties. Such regulations also govern:
•interstate and intrastate pipeline transportation rates for oil, natural gas and NGLs in regulated pipeline systems;
•prevention of market manipulation in the oil, natural gas, NGL and power markets;
•market transparency rules with respect to natural gas and power markets;
•the physical and futures energy commodities market, including financial derivative and hedging activity; and
•prevention of discrimination in natural gas gathering operations in favor of producers or sources of supply.
The federal and state agencies overseeing these regulations have substantial rate-setting and enforcement authority, and violation of the foregoing regulations could expose us to litigation with government authorities, counterparties, special interest groups and others.
International treaties and regulations also affect the marketing or sale of our products. For example, on January 1, 2020, the International Maritime Organization reduced the maximum sulfur content in marine fuels from 3.5% to 0.5% by weight under the International Convention for the Prevention of Pollution from Ships. Under this IMO 2020 rule, ships must either switch to low-sulfur fuels or install scrubbing facilities for emission controls, which may affect the price of and demand for varying grades of crude oil, both internationally and in California.
In addition, mandates or subsidies have been adopted or proposed by the state and certain local governments to require or promote renewable energy or electrification of transportation, appliances and equipment, or prohibit or restrict the use of petroleum products, by our customers or the public. For example, in January 2020, the California Public Utilities Commission (CPUC) commenced a rulemaking to develop a long-term natural gas planning strategy to ensure safe and reliable gas systems at just and reasonable rates during what it describes as a 25-year transition from natural gas-fueled technologies to meet the state's GHG goals. In addition, several municipalities in California enacted ordinances in 2019 that restrict the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect the retail natural gas market of our utility customers and the demand and prices we receive for the natural gas we produce. Several of these ordinances face legal challenges.
We make available, free of charge on our website www.crc.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Definitive Proxy Statements and amendments to those reports filed or furnished, if any, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Unless otherwise provided herein, information contained on our website is not part of this report. The SEC maintains an internet site, http://www.sec.gov, that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.
ITEM 1A RISK FACTORS
Described below are certain risks and uncertainties that could adversely affect our business, financial condition, results of operations or cash flow. These risks are not the only risks we face. Our business could also be affected materially and adversely by other risks and uncertainties that are not currently known to us or that we currently deem to be insignificant.
Risks Related to Our Business
Prices for our products can fluctuate widely and an extended period of low prices could adversely affect our financial condition, results of operations, cash flow and ability to invest in our assets.
Our financial condition, results of operations, cash flow and ability to invest in our assets are highly dependent on oil, natural gas and NGL prices. A sustained period of low prices for oil, natural gas and NGLs would reduce our cash flows from operations and could reduce our borrowing capacity or cause a default under our financing agreements. In particular, as described in the risk factor below, the COVID-19 pandemic and related economic repercussions have had a significant impact on commodity prices. During the second quarter of 2020, the price of Brent crude oil reached a historic low of just under $20 per barrel. The current futures forward curve for Brent crude indicates that prices are expected to continue at about current levels for an extended time. The estimated average benchmark Brent oil price used to determine our December 31, 2020 reserves was $41.77 per barrel as compared to the average benchmark Brent oil price used to determine our 2019 year-end reserves of $63.15 per barrel, both based on SEC pricing.
Prices for oil, natural gas and NGL may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:
•changes in domestic and global supply and demand;
•domestic and global inventory levels;
•political and economic conditions;
•the actions of OPEC and other significant producers and governments;
•changes or disruptions in actual or anticipated production, refining and processing;
•worldwide drilling and exploration activities;
•government energy policies and regulation, including with respect to climate change;
•the effects of conservation;
•weather conditions and other seasonal impacts;
•speculative trading in derivative contracts;
•currency exchange rates;
•transportation and storage capacity, bottlenecks and costs in producing areas;
•the price, availability and acceptance of alternative energy sources;
•regional market conditions; and
•other matters affecting the supply and demand dynamics for these products.
Lower prices could have adverse effects on our business, financial condition, results of operations and cash flow, including:
•reducing our proved oil and natural gas reserves over time, including as a result of impairments of existing reserves;
•limiting our ability to grow or maintain future production including a delay in the reversion dates of certain of our JVs;
•causing a reduction in our borrowing base under our Revolving Credit Facility, which could affect our liquidity;
•reducing our ability to make interest payments or maintain compliance with financial covenants in the agreements governing our indebtedness, which could trigger mandatory loan repayments and default and foreclosure by our lenders and bondholders against our assets;
•affecting our ability to attract counterparties and enter into commercial transactions, including hedging, surety or insurance transactions; and
•limiting our access to funds through the capital markets and the price we could obtain for asset sales or other monetization transactions.
Our hedging program does not provide downside protection for all of our production. As a result, our hedges do not fully protect us from commodity price declines, and we may be unable to enter into acceptable additional hedges in the future.
The COVID-19 pandemic caused crude oil prices to decline significantly in 2020, which has materially and adversely affected our business, results of operations and financial condition.
The COVID-19 pandemic has adversely affected the global economy, and has resulted in, among other things, travel restrictions, business closures and the institution of quarantining and other mandated and self-imposed restrictions on movement. As a result, there has been an unprecedented reduction in demand for crude oil. The severity, magnitude and duration of current or future COVID-19 outbreaks, the extent of actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. Lower future commodity prices caused by the COVID-19 pandemic could force us to reduce costs, including by decreasing operating expenses and lowering capital expenditures, and such actions could negatively affect future production and our reserves. Starting in March 2020, we reduced our operating expenses and planned capital expenditures to those necessary to maintain mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner. In addition, we shut-in wells which reduced our 2020 net production by 3 MBoe/d. These operational decisions negatively impacted our production and may materially and adversely affect the quantity of estimated proved reserves that may be attributed to our properties. Our operations also may be adversely affected if significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions or other restrictions in connection with the pandemic. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile.
Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global business and economic environment adversely affects our business and financial results, it may also have the effect of heightening or exacerbating many of the other risks described in the “Risk Factors” herein.
Recent and future actions by the state of California could result in restrictions to our operations and result in decreased demand for oil and gas within the state.
In September 2020, Governor Gavin Newsom of California issued an executive order (Order) that seeks to reduce both the demand for and supply of petroleum fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of GHGs, including, but not limited to: phasing out the sale of new emissions-producing passenger vehicles, drayage trucks and off-road vehicles by 2035 and, to the extent feasible, medium and heavy duty trucks by 2045; developing strategies for the closure and repurposing of oil and gas facilities in California; and proposing legislation to end the issuance of new hydraulic fracturing permits in the state by 2024. The Order also directs the California Department of Conservation, Geologic Energy Management Division (CalGEM) to strictly enforce bonding requirements for oil and gas operations and to complete its ongoing public health and safety review of oil production and propose additional regulations, which are expected to include expanded land use setbacks or buffer zones. In October 2020, the Governor issued an executive order that establishes a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directs state agencies to implement other measures to mitigate climate change and strengthen biodiversity. In February 2021, SB 467 was introduced in the state senate. If passed, the bill would ban new permits for hydraulic fracturing, acid well stimulation treatments, cyclic steaming, water flooding and steam flooding – beginning in 2022 and would ban these activities beginning in 2027. The bill would also allow local governments to prohibit such practices prior to 2027. After the bill was introduced one of the authors announced that it would also be amended to also add a 2,500 feet setback for new wells from sensitive receptors. We cannot predict the outcome of this most recent legislative effort. Previous high profile efforts to pass mandatory setbacks have failed; however, any of the foregoing developments and other future actions taken by the state may materially and adversely affect our operations and properties and the demand for our products.
Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans.
Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products. Federal, state and local agencies may assert overlapping authority to regulate these areas. For example, 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 plan to issue additional regulations governing various oil and natural gas activities in the future. On November 9, 2020, the EPA approved reclassification of the South Coast Air Quality Management District non-attainment area for the 2012 fine particulate matter National Ambient Air Quality Standard to “serious nonattainment,” which requires California to submit an attainment plan to achieve attainment as expeditiously as practicable. Any restrictions imposed by California pursuant to any future attainment plan to comply with this designation of serious nonattainment may result in increased compliance costs and adversely affect our business and results of operations. In addition, certain of these federal, state and local 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.
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, stimulation, operation, inspection, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection and disposal and water consumption, recycling and reuse. Failure to comply may result in the assessment of administrative, civil and/or criminal fines and penalties, 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 prohibiting certain operations or our access to property, water, minerals or other necessary resources, and may otherwise delay or restrict our operations and cause us to incur substantial costs. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties 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.
Our customers, including refineries and utilities, and the businesses that transport our products to customers, are also highly regulated. For example, various government authorities have sought to restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics. Federal and state pipeline safety agencies have adopted or proposed regulations to expand their jurisdiction to include more gas and liquid gathering lines and pipelines and to impose additional mechanical integrity, leak detection and reporting requirements. The state has adopted additional regulations on the storage of natural gas that could affect the demand for or availability of such storage, increase seasonal volatility, or otherwise affect the prices we receive from customers. The California Public Utilities Commission (CPUC) has commenced a rulemaking to develop a long-term natural gas planning strategy to ensure safe and reliable gas systems at just and reasonable rates during what it describes as a 25-year transition from natural gas-fueled technologies to meet the state’s GHG goals. 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.
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. For example, the California legislature expanded CalGEM duties in 2019 to include public health and safety and CalGEM is expected to complete a review of potential public health and safety concerns resulting from the impacts of oil and gas extraction activities by the first half of 2021 and to propose a rulemaking to address the findings of the agency’s review. Government authorities have also adopted or proposed new or more stringent requirements for permitting, inspection and maintenance of wells, pipelines and other facilities, and public disclosure or environmental review of, or restrictions on, oil and natural gas operations, including proposed setback distances or buffer zones from other land uses, as well as proposals to declare oil and gas production a non-conforming use in certain jurisdictions in an effort to prevent future development or phase out existing production over time. Such requirements or associated litigation could result in potentially significant added costs to comply, delay or curtail our exploration, development, fluid injection and disposal or production activities, preclude us from drilling, completing or stimulating wells, or otherwise restrict our ability to access and develop mineral rights, any of which could have an adverse effect on our expected production, other operations and financial condition.
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 Governor of California or the California 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 at the federal level with respect to health, environmental safety, climate, labor or energy laws, regulations and policies, including those that may directly or indirectly impact our operations.
Recent actions by the Biden administration could result in restrictions to our operations
In January 2021, the U.S. Department of the Interior announced that it was restricting its employees for a period of 60 days, other than senior identified leadership, from approving certain activities including entering into new leases or approving drilling permits on public lands and waters. Approximately 9% of our net production is on federal lands and the Biden administration may extend such restrictions or add others that make it more difficult or costly to operate on these lands.
Drilling for and producing oil and natural gas carry significant operational and financial risks and uncertainty. We may not drill wells at the times we scheduled, or at all. Wells we do drill may not yield production in economic quantities or generate the expected payback.
The exploration and development of oil and natural gas properties depend in part on our analysis of geophysical, geologic, engineering, production and other technical data and processes, including the interpretation of 3D seismic data. This analysis is often inconclusive or subject to varying interpretations. We also bear the risks of equipment failures, accidents, environmental hazards, unusual geological formations or unexpected pressure or irregularities within formations, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes, disappointing drilling results or reservoir performance (including lack of production response to workovers or improved and enhanced recovery efforts) and other associated risks.
Our decisions and ultimate profitability are also affected by commodity prices, the availability of capital, regulatory approvals, available transportation and storage capacity, the political environment and other factors. Our cost of drilling, completing, stimulating, equipping, operating, inspecting, maintaining and abandoning wells is also often uncertain.
Any of the forgoing operational or financial risks could cause actual results to differ materially from the expected payback or cause a well or project to become uneconomic or less profitable than forecast.
We have specifically identified locations for drilling over the next several years, which represent a significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. 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. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate. We cannot guarantee that our identified drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these drilling locations. In addition, some of our leases could expire if we do not establish production in the leased
acreage. The combined net acreage covered by leases expiring in the next three years represented 17% of our total net undeveloped acreage at December 31, 2020.
Our business can involve substantial capital investments, which may include acquisitions or JVs. We may be unable to fund these investments which could lead to a decline in our oil and natural gas reserves or production. Our capital investment program is also susceptible to risks that could materially affect its implementation.
Our exploration, development and acquisition activities can involve substantial capital investments. Following our emergence from Chapter 11 bankruptcy, our capital investments will mainly be funded through a combination of cash flow from operations and borrowings under our Revolving Credit Facility. We seek to manage our internally funded capital investments to align with projected cash flow from operations. Accordingly, a reduction in projected operating cash flow could cause us to reduce our future capital investments. In general, the ability to execute our capital plan depends on a number of factors, including:
•the amount of oil, natural gas and NGLs we are able to produce;
•regulatory and third-party approvals;
•our ability to timely drill, complete and stimulate wells;
•our ability to secure equipment, services and personnel; and
•the availability of external sources of financing.
Access to future capital may be limited by our lenders, our JV partners, capital markets constraints, activist funds or investors, or poor stock price performance. Because of these and other potential variables, we may be unable to deploy capital in the manner planned, which may negatively impact our production levels and development activities and limit our ability to make acquisitions or enter into JVs.
Unless we make sufficient capital investments and conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our ability to make the necessary long-term capital investments or acquisitions needed to maintain or expand our reserves may be impaired to the extent we have insufficient cash flow from operations or liquidity to fund those activities. Over the long term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.
From time to time we may engage in exploratory drilling, including drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.
The risk profile for our exploration drilling locations is higher than for other locations because we have less geologic and production data and drilling history, in particular for those exploration drilling locations in unconventional reservoirs, which are in unproven geologic plays. Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, capital availability, costs, drilling results, regulatory approvals, available transportation capacity and other factors. We may not find commercial amounts of oil or natural gas or the costs of drilling, completing, stimulating and operating wells in these locations may be higher than initially expected. 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. In either case, the value of our undeveloped acreage may decline and could be impaired.
Our producing properties are located exclusively in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.
Our operations are concentrated in California. Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions. These include local price fluctuations, changes in state or regional laws and regulations affecting our operations and other regional supply and demand factors, including gathering, pipeline, transportation and storage capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. Our operations are also exposed to natural disasters and related events common to California, such as wildfires, mudslides, high winds and earthquakes. Further, our operations may be exposed to power outages, mechanical failures, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells
to be shut in, delay operations and growth plans, decrease cash flows, increase operating and capital costs, prevent development of lease inventory before expiration and limit access to markets for our products.
Many of our current and potential competitors have or may potentially have greater resources than we have and we may not be able to successfully compete in acquiring, exploring and developing new properties.
We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods and services and hiring and retaining employees needed to operate and manage our business and marketing natural gas, NGLs or oil. Competitors include multinational oil companies, independent production companies and individual producers and operators. In California, our competitors are few and large, which may limit available acquisition opportunities. Many of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address such competitive factors more effectively than we can or withstand industry downturns more easily than we can.
Our commodity price risk-management activities may prevent us from fully benefiting from price increases and may expose us to other risks.
Our commodity price risk-management activities may prevent us from realizing the full benefits of price increases above any levels set in certain derivative instruments we may use to manage price risk. In addition, our commodity price risk-management activities may 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.
Under the Revolving Credit Facility, we are required to maintain acceptable commodity hedges hedging no less than (i) 75% of our reasonably anticipated oil production from our proved reserves for the first 24 months after the closing of the Revolving Credit Facility, which occurred upon emergence from bankruptcy and (ii) 50% of our reasonably anticipated oil production from our proved reserves for a period from the 25th month through the 36th month after the same date. The Revolving Credit Facility specifies the forms of hedges and prices (which can be prevailing prices) that must be used.
For the remaining duration of the Revolving Credit Facility, we must maintain acceptable commodity hedges for no less than 50% of the reasonably anticipated total forecasted production of crude oil from our oil and gas properties for at least 24 months following the date of delivery of each reserve report. We may not hedge more than 80% of reasonably anticipated total forecasted production of crude oil, natural gas and NGLs from our oil and gas properties for a 48-month period.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), enacted in 2010, established federal oversight and regulation of the over-the-counter (OTC) derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the U.S. Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions. These regulations may affect both the size of positions that we may enter and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, the effects of these regulations could reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices.
In addition, U.S. regulators adopted a final rule in November 2019 implementing a new approach for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory capital rules, referred to as the standardized approach for counterparty credit risk (SA-CCR). Certain financial institutions are required to comply with the new SA-CCR rules beginning on January 1, 2022. The new rules could significantly increase the capital requirements for certain participants in the OTC derivatives market in which we participate. These increased capital requirements could result in significant additional costs being passed through to end users like us or reduce the number of participants or products available to us in the OTC derivatives market. These regulations could result in a reduction in our hedging opportunities or substantially increase our cost of hedging, which could adversely affect our business, financial condition and results of operations.
The European Union and other non-U.S. jurisdictions may implement 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 impacted by such regulations, which could also adversely affect our hedging opportunities.
Our actual financial results after emergence from bankruptcy may differ significantly from the projections included in our Plan. In addition, our actual financial results may not be comparable to our historical financial information as a result of the implementation of our Plan and our adoption of fresh start accounting.
In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of our Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of our Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.
In addition, upon our emergence from bankruptcy, we adopted fresh start accounting, as a result of which our assets and liabilities were recorded at fair value, which are materially different than the amounts reflected in our historical financial statements. Accordingly, our future financial statements may not be comparable to our historical financial statements.
Risks Related to our Indebtedness
Our existing and future indebtedness may adversely affect our cash flows and ability to operate our business, remain in compliance and repay our debt.
As of December 31, 2020, we had $599 million of total long-term debt, and additional borrowing capacity of $307 million under the Revolving Credit Facility (after taking into account $134 million of outstanding letters of credit). In addition, as of December 31, 2020, on a pro forma basis giving effect to the January 2021 issuance of our Senior Notes as described in Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity, High Yield Debt Offering, we would have had approximately $397 million available for borrowing under the Revolving Credit Facility (after taking into account $134 million of outstanding letters of credit). The indenture that governs the Senior Notes permits us to incur significant additional debt, some of which may be secured. Our level of indebtedness could affect our operations in several ways, including the following:
•limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•require us to dedicate a portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities due to restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
•increase our vulnerability to downturns and adverse developments in our business and the economy generally;
•limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses, or to refinance existing indebtedness;
•make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;
•make us vulnerable to increases in interest rates as our indebtedness under the Revolving Credit Facility varies with prevailing interest rates;
•place us at a competitive disadvantage relative to our competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
•make it more difficult for us to satisfy our obligations under the Senior Notes or other debt and increase the risk that we may default on our debt obligations.
Our ability to satisfy our obligations depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. Our business may not generate sufficient cash flow, and future financings may not be available to provide sufficient net proceeds, to meet these obligations or to successfully execute our business strategy.
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 the obligations under our indebtedness, which may not be successful.
Our earnings and cash flow could vary significantly from year to year due to the nature of our industry despite our commodity price risk-management activities. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments at that time. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control as discussed in this “Risk Factors” section. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
Our lenders could limit our borrowing capabilities and restrict our ability to use or access capital.
Our Revolving Credit Facility is an important source of our liquidity. Our ability to borrow under our Revolving Credit Facility is limited by our borrowing base, the size of our lenders’ commitments and our ability to comply with covenants, including various leverage ratios, hedging requirements and reporting obligations.
The borrowing base under our Revolving Credit Facility is redetermined semi-annually on April 1 and October 1 of each year. Our lenders determine our borrowing base by reference to the value of our reserves and other factors that the administrative agent may deem appropriate in good faith in accordance with its usual and customary oil and gas lending criteria as they exist at the particular time. The lenders under our Revolving Credit Facility may also factor other liabilities, including our other indebtedness, into the determination of our borrowing base. Currently, our borrowing base is set at $1.2 billion. Availability under our Revolving Credit Facility is the least of (i) the then-effective borrowing base, (ii) the then-effective aggregate commitments and (iii) the aggregate elected commitment amount, which is currently set at $540 million. The aggregate revolving commitment is subject to an automatic reduction if additional commitments from new lenders are not obtained. As a result, we expect the aggregate commitment of our lenders will be reduced to $492 million in April 2021.
Any reduction in our borrowing base could materially and adversely affect our liquidity and may hinder our ability to execute on our business strategy.
Restrictive covenants in our Revolving Credit Facility may limit our financial and operating flexibility.
As of December 31, 2020, total outstanding borrowings under the Revolving Credit Facility were $99 million and we had $307 million of available borrowing capacity after taking into account $134 million of outstanding letters of credit. Our Revolving Credit Agreement permits us to incur significant additional indebtedness as well as certain other obligations. In addition, we may seek amendments or waivers from our existing lenders to the extent we need to incur indebtedness above amounts currently permitted by our financing agreements.
Our Revolving Credit facility contains certain restrictions, which may have adverse effects on our business, financial condition, cash flows or results of operations, limiting our ability, among other things, to:
•incur additional indebtedness;
•incur additional liens;
•pay dividends or make other distributions;
•make investments, loans or advances;
•sell or discount receivables;
•enter into mergers;
•enter into or terminate hedge agreements;
•enter into transactions with affiliates;
•maintain gas imbalances;
•enter into take-or-pay contracts or make other prepayments;
•enter into sale and leaseback agreements;
•prepay or modify the terms of junior debt;
•enter into negative pledge agreements;
•enter into production sharing contracts;
•amend our organizational documents; and
•make capital investments.
The Revolving Credit Agreement also requires us to comply with certain financial maintenance covenants, including a leverage ratio and current ratio.
A breach of any of these restrictive covenants could result in a default under the Revolving Credit Facility. If a default occurs, the lenders may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. If we are unable to repay our indebtedness when due or declared due, the lenders thereunder will also have the right to proceed against the collateral pledged to them to secure the indebtedness.
Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. In addition, uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future indebtedness.
Borrowings under our Revolving Credit Facility are at variable rates of interest and expose us to interest rate risk. As such, our results of operations are sensitive to movements in interest rates. There are many economic factors outside our control that have in the past and may, in the future, impact rates of interest including publicly announced indices that underlie the interest obligations related to a certain portion of our debt. Factors that impact interest rates include governmental monetary policies, inflation, economic conditions, changes in unemployment rates, international disorder and instability in domestic and foreign financial markets. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our results of operations would be adversely impacted. Such increases in interest rates could have a material adverse effect on our financial condition and results of operations.
In addition, a transition away from the London Interbank Offered Rate (LIBOR) as a benchmark for establishing the applicable interest rate may affect the cost of servicing our debt under the Revolving Credit Facility. The Financial Conduct Authority of the United Kingdom has announced that it plans to phase out LIBOR by the end of calendar year 2021. Although the Revolving Credit Agreement provides for alternative base rates, such alternative base rates may or may not be related to LIBOR, and the consequences of the phase out of LIBOR cannot be entirely predicted at this time. For example, if any alternative base rate or means of calculating interest with respect to our outstanding variable rate indebtedness leads to an increase in the interest rates charged, it could result in an increase in the cost of such indebtedness, impact our ability to refinance some or all of our existing indebtedness or otherwise have a material adverse impact on our business, financial condition and results of operations. Further, the discontinuation, reform or replacement of LIBOR or any other benchmark rates may have an unpredictable impact on contractual mechanics in the credit markets or cause disruption to the broader financial markets.
Risks Related to Our Common Stock
The trading price of our common stock may decline, and you may not be able to resell shares of our common stock at prices equal to or greater than the price you paid or at all.
The trading price of our common stock may decline for many reasons, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. Numerous factors, including those referred to in this “Risk Factors” section could affect our stock price. These factors include, among other things, changes in our results of operations and financial condition; changes in commodity prices; changes in the national and global economic outlook; changes in
applicable laws and regulations; variations in our capital plan; changes in financial estimates by securities analysts or ratings agencies; changes in market valuations of comparable companies; and additions or departures of key personnel.
Future sales of our common stock 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.
We may sell additional shares of common stock in subsequent public or private offerings. We may also issue additional shares of common stock or convertible securities. As of February 28, 2021, we had 83,319,660 outstanding shares of common stock and 4,384,182 shares of common stock issuable upon exercise of outstanding warrants. We cannot predict the size of 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.
There is an increased potential for short sales of our common stock due to the sales of shares issued upon exercise of warrants, which could materially affect the market price of the stock.
Downward pressure on the market price of our common stock that likely will result from sales of our common stock issued in connection with the exercise of warrants could encourage short sales of our common stock by market participants. Generally, short selling means selling a security, contract or commodity not owned by the seller. The seller is committed to eventually purchase the financial instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s price. Such sales of our common stock could have a tendency to depress the price of the stock, which could increase the potential for short sales..
The ownership position of certain of our stockholders limits other stockholders’ ability to influence corporate matters and could affect the price of our common stock.
Based on the most recent available public information, four of our shareholders collectively own approximately 72% of our common stock. As a result, each of these stockholders, or any entity to which such stockholders sell their stock, may be able to exercise significant control over matters requiring stockholder approval. Further, because of this large ownership position, if these stockholders sell their stock, the sales could depress our share price.
General Risk Factors
Concerns about climate change and other air quality issues may materially affect our operations or results.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions, and regulation of GHGs and other air quality issues, may materially affect our business in many ways, including increasing the costs to provide our products and services and reducing demand for, and consumption of, our products and services, and we may be unable to recover or pass through a significant portion of our costs. In addition, legislative and regulatory responses to such issues at the federal, state and local level may increase our capital and operating costs and render certain wells or projects uneconomic, and potentially lower the value of our reserves and other assets. Both the EPA and California have implemented laws, regulations and policies that seek to reduce GHG emissions. California’s cap-and-trade program operates under a market system and the costs of such allowances per metric ton of GHG emissions are expected to increase in the future as the CARB tightens program requirements and annually increases the minimum state auction price of allowances and reduces the state’s GHG emissions cap. As the foregoing requirements become more stringent, we may be unable to implement them in a cost-effective manner, or at all. In recent years, the regulation of methane emissions from oil and gas facilities has been subject to uncertainty. 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, on January 20, 2021, President Biden signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities.
Internationally, the United Nations-sponsored Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has signed
executive orders recommitting to the Paris Agreement, and calling on the federal government to develop the United States' emissions reduction target. In addition, the current and former Governor of California and certain municipalities in California have announced their commitment to adhere to GHG reductions called for in the Paris Agreement through executive orders, pledges, resolutions and memoranda of understanding or other agreements with various other countries, U.S. states, Canadian provinces and municipalities.
Concern over climate change and GHG and other emissions has also resulted in increasing political risks in California and the United States, including climate change related pledges made by various candidates for and holders of public office. On January 27, 2021 President Biden issued an executive order calling 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 governmental agencies and economic sectors. The January 27 order also suspends the issuance of new leases for oil and gas development on federal lands, to the extent permitted by law, pending completion of a review of current practices. Other actions that could be pursued by President Biden include more restrictive requirements for the establishment of pipeline infrastructure or other GHG emissions limitations for oil and gas facilities, which could negatively impact our operations and the value or use of our properties. Additionally, various claimants, including certain municipalities, have filed litigation alleging that energy producers are liable for damages attributed to climate change. Suits have also been brought against such companies under shareholder and consumer protection laws, alleging that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts.
In addition, other current and proposed international agreements and federal, state and local laws, regulations and policies seek to restrict or reduce the use of petroleum products in transportation fuels, electricity generation, plastics and other applications, prohibit future sale or use of vehicles, appliances or equipment that require petroleum fuels, impose additional taxes and costs on producers and consumers of petroleum products and require or subsidize the use of renewable energy. California has set an ambitious goal by executive order to be “carbon-neutral” by 2045 and initiated and funded studies to identify strategies to implement this goal. The California legislature, state agencies and various municipalities have adopted or proposed laws, regulations and policies that seek to significantly reduce emissions from vehicles, increase the use of “zero emission” vehicles, reduce the use of plastics, increase renewable energy mandates for utilities and in residential and commercial construction, and replace natural gas appliances and infrastructure in residential and commercial buildings with electric appliances.
Government authorities can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations, and various state and local agencies are conducting increased regional, community and field air monitoring specifically with respect to oil and natural gas operations. In addition, California air quality laws and regulations, particularly in Southern and Central California where most of our operations are located, are in most instances more stringent than analogous federal laws and regulations. For example, the San Joaquin Valley will be required to adopt more rigorous attainment plans under the Clean Air Act to comply with federal ozone and particulate matter standards, and these efforts could affect our activities in the region and our ability and cost to obtain permits for new or modified operations.
To the extent financial markets view climate change and GHG or other emissions as an increasing financial risk, this could adversely impact our cost of, and access to, capital and the value of our stock and our assets. Current investors in oil and gas companies may elect in the future to shift some or all of their investments into other sectors, and institutional lenders may elect not to provide funding for oil and gas companies. Additionally, proponents of the Paris Agreement, including various state agencies and municipalities in California, and other governmental and non-governmental organizations concerned about climate change have sought to pressure public and private investment funds not to invest in oil and gas companies and institutional lenders to restrict oil and gas companies’ access to capital. Recently, President Biden issued an executive order calling for the development of a "climate finance plan", and, separately, the Federal Reserve announced that it has applied to join the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financings for oil and gas companies like us could result in the restriction, delay or cancellation of drilling programs or development or production activities.
We believe, but cannot guarantee, that our local production of oil, NGLs and natural gas will remain essential to meeting California’s energy and feedstock needs for the foreseeable future. We have also established 2030 Sustainability Goals for water recycling, renewables integration, methane emission reduction and carbon capture and sequestration in our life-of-field planning in an attempt to align with the state’s long-term goals and support our
ability to continue to efficiently implement federal, state and local laws, regulations and policies, including those relating to air quality and climate, in the future. However, there can be no assurances that we will be able to design, permit, fund and implement such projects in a timely and cost-effective manner or at all, or that we, our customers or end users of our products will be able to satisfy long-term environmental, air quality or climate goals if those are applied as enforceable mandates.
The adoption and implementation of new or more stringent international, federal, state or local legislation, regulations or policies that impose more stringent standards for GHG or other emissions from our operations or otherwise restrict the areas in which we may produce oil, natural gas, NGLs or electricity or generate GHG or other emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or the value of our products and services. Additionally, political, litigation and financial risks may result in restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages or other losses as a result of climate change, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may pose increasing risks of physical impacts to our operations and those of our suppliers, transporters and customers through damage to infrastructure and resources resulting from drought, wildfires, sea level changes, 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 operations.
Adverse tax law changes may affect our operations.
We are subject to taxation by various tax authorities at the federal, state and local levels where we do business. New legislation could be enacted by any of these government authorities that could adversely affect our business. Legislation has been previously proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. However, it is unclear whether any such changes will be enacted and, if enacted, how soon any such changes would be effective. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced demand for our products. The passage of any such legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, or could increase costs and any such changes could have an adverse effect on our financial condition, results of operations and cash flows.
In California, there have been numerous state and local proposals for additional income, sales, excise and property taxes, including additional taxes on oil and natural gas production. Although such proposals targeting our industry have not become law, campaigns by various interest groups could lead to additional future taxes.
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.
Many uncertainties exist in estimating quantities of proved reserves and related future net cash flows. Our estimates are based on various assumptions that require significant judgment in the evaluation of available information. Our assumptions may ultimately prove to be inaccurate. Additionally, reservoir data may change over time as more information becomes available from development and appraisal activities.
Our ability to add reserves, other than through acquisitions, depends on the success of improved recovery, extension and discovery projects, each of which depends on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside management’s control and will affect whether the historical sources of proved reserves additions continue to provide reserves at similar levels.
Generally, lower prices adversely affect the quantity of our reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. In addition, a portion of our proved undeveloped reserves may no longer meet the economic producibility criteria under the applicable rules or may be removed due to a lower amount of capital available to develop these projects within the SEC-mandated five-year limit.
In addition, our reserves information represents estimates prepared by internal engineers. Although over 80% of our estimated proved reserve volumes as of December 31, 2020 were audited by our independent petroleum engineers, Ryder Scott and NSAI, we cannot guarantee that the estimates are accurate.
Reserves estimation is a partially subjective process of estimating accumulations of oil and natural gas. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows from those reserves depend upon a number of variables and assumptions, including:
•historical production from the area compared with production from similar areas;
•the quality, quantity and interpretation of available relevant data;
•production and operating costs;
•ad valorem, excise and income taxes;
•the effects of government regulations; and
•future workover and facilities costs.
Changes in these variables and assumptions could require us to make significant negative reserves revisions, which could affect our liquidity by reducing the borrowing base under our Revolving Credit Facility. In addition, 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.
Acquisition and disposition activities involve substantial risks.
Our acquisition activities carry risks that we may:
•not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances;
•bear unexpected integration costs or experience other integration difficulties;
•assume liabilities that are greater than anticipated; and
•be exposed to currency, political, marketing, labor and other risks.
In connection with our acquisitions, we are often only able to perform limited due diligence. Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing for recovering the reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact and incomplete, and we may be unable to make these assessments with a high degree of accuracy. If we are not able to make acquisitions, we may not be able to grow our reserves or develop our properties in a timely manner or at all.
Part of our business strategy involves divesting non-core assets. We regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Our disposition activities carry risks that we may:
•not be able to realize reasonable prices or rates of return for assets;
•be required to retain liabilities that are greater than desired or anticipated;
•experience increased operating costs; and
•reduce our cash flows if we cannot replace associated revenue.
There can be no assurance that we will be able to divest assets on financially attractive terms or at all. Our ability to sell assets is also limited by the agreements governing our indebtedness. If we are not able to sell assets as needed, we may not be able to generate proceeds to support our liquidity and capital investments.
We may incur substantial losses and be subject to substantial liability claims as a result of pollution, environmental conditions or catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not fully insured against all risks. Our oil and natural gas exploration and production activities and our assets are subject to risks such as fires, explosions, releases, discharges, power outages, equipment or information
technology failures and industrial accidents, as are the assets and properties of third parties who supply us with energy, equipment and services or who purchase, transport or use our products. Pollution or environmental conditions with respect to our operations or on or from our properties, whether arising from our operations or those of our predecessors or third parties, could expose us to substantial costs and liabilities. In addition, events such as earthquakes, floods, mudslides, wildfires, power outages, high winds, droughts, cybersecurity, vandalism or terrorist attacks and other events may cause operations to cease or be curtailed and could adversely affect our business, workforce and the communities in which we operate. Further, recent wildfires experienced in California have limited the availability and increased the cost of obtaining insurance against certain natural disasters. 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.
Information technology failures and cybersecurity attacks could adversely affect us.
We rely on electronic systems and networks to communicate, control and manage our exploration, development and production activities. We also use these systems and networks to prepare our financial management and reporting information, to analyze and store data and to communicate internally and with third parties, including our service providers and customers. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected.
Cybersecurity attacks on businesses have escalated and become more sophisticated in recent years and include attempts to gain unauthorized access to data, malicious software, ransomware and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential information or the corruption of data. In addition, our vendors, customers and other business partners may separately suffer disruptions or breaches from cybersecurity attacks that, in turn, could adversely impact our operations and compromise our information. If we or the third parties with whom we interact were to experience a successful attack, the potential consequences to our business, workforce and the communities in which we operate could be significant, including financial losses, loss of business, litigation risks and damage to reputation. As the sophistication of cybersecurity attacks continues to evolve, we may be required to expend additional resources to further enhance our security.
Increasing attention to environmental, social and governance (ESG) matters may adversely impact our business.
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 evaluate their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of their investment away from the fossil fuel industry to other industries which could have a negative impact on our stock price and our access to and costs of capital.
ITEM 1B UNRESOLVED STAFF COMMENTS
ITEM 3LEGAL PROCEEDINGS
For information regarding legal proceedings, see Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Lawsuits, Claims, Commitments and Contingencies and Part II, Item 8 – Financial Statements and Supplementary Data – Note 10 Lawsuits, Claims, Commitments and Contingencies.
ITEM 4MINE SAFETY DISCLOSURES
ITEM 5MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information for Common Stock
On October 27, 2020, the Successor company's common stock was listed under the symbol "CRC" on the New York Stock Exchange (NYSE). During the period from July 16, 2020 through October 26, 2020, the Predecessor company’s common stock was quoted on the OTC Pink Market under the symbol “CRCQQ”. Prior to July 16, 2020, the Predecessor company’s common stock was listed on the NYSE under the symbol “CRC”.
Holders of Record
Our common stock was held by approximately 175 stockholders of record at December 31, 2020.
We have not declared or paid dividends on either the Predecessor or the Successor company’s respective common stock during 2019 or 2020. Our Revolving Credit Facility generally restricts the payment of dividends on our stock, subject to certain exceptions. Currently, we do not pay dividends, but may do so in future periods depending on our ability to do so under our Revolving Credit Facility.
Securities Authorized for Issuance Under Equity Compensation Plans
On May 26, 2020, our then Board of Directors approved the termination of the California Resources Corporation 2014 Employee Stock Purchase Plan. No additional shares were issued under the plan after March 31, 2020.
On October 27, 2020 in connection with our emergence from bankruptcy, the Amended and Restated California Resources Corporation Long-Term Incentive Plan and all outstanding awards thereunder were cancelled.
On January 18, 2021, our Board of Directors approved the California Resources Corporation 2021 Long Term Incentive Plan (2021 Incentive Plan). The shares issuable under the new long-term incentive plan had been previously authorized by the United States Bankruptcy Court for the Southern District of Texas in connection with our emergence from Chapter 11 of the Bankruptcy Code and the terms of the new long-term incentive plan were approved by our Board of Directors. As a result, the 2021 Incentive Plan became effective on January 18, 2021. The 2021 Incentive Plan provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, vested stock awards, dividend equivalents, other stock-based awards and substitute awards to employees, officers, non-employee directors and other service providers of the Company and its affiliates. The 2021 Incentive Plan provides for the reservation of 9,257,740 shares of common stock for future issuances, subject to adjustment as provided in the 2021 Incentive Plan. Shares of stock subject to an award under the 2021 Incentive Plan that expires or is cancelled, forfeited, exchanged, settled in cash or otherwise terminated without the actual delivery of shares (restricted stock awards are not considered “delivered shares” for this purpose) will again be available for new awards under the 2021 Incentive Plan. However, (i) shares tendered or withheld in payment of any exercise or purchase price of an award or taxes relating to awards, (ii) shares that were subject to an option or a stock appreciation right but were not issued or delivered as a result of the net settlement or net exercise of the option or stock appreciation right, and (iii) shares repurchased on the open market with the proceeds from the exercise price of an option, will not, in each case, again be available for new awards under the 2021 Incentive Plan.
ITEM 6SELECTED FINANCIAL DATA
ITEM 7MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with other sections of this report, including but not limited to, Part I, Item 1 and 2 – Business and Properties and Part II, Item 8 – Financial Statements and Supplementary Data.
Basis of Presentation
All financial information presented consists of our consolidated results of operations, financial position and cash flows unless otherwise indicated. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas production activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our balance sheets and statements of operations and cash flows.
We emerged from Chapter 11 bankruptcy proceedings on October 27, 2020 as further described below. We adopted and applied the relevant guidance with respect to the accounting and financial reporting for entities that have emerged from bankruptcy proceedings. Under fresh start accounting, the reorganized entity is considered a new reporting entity. We elected to apply fresh start accounting effective October 31, 2020, an accounting convenience date, and the $2.5 billion reorganization value of the emerging entity was assigned to individual assets and liabilities based on their estimated relative fair values. As such, fresh start accounting was reflected on our consolidated balance sheet as of October 31, 2020. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. References to "Predecessor” refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.
Certain operating results and key operating performance measures, for example production, average realized prices, revenues, operating expense, taxes other than on income and general and administrative expenses, were not significantly impacted by the reorganization. Accordingly, we believe that discussing the combined results of operations and cash flows of the Predecessor and Successor companies is useful when analyzing financial results and performance measures. For items that are not comparable, for example depreciation, depletion and amortization, interest expense, impairment and net income (loss), we have included additional analysis.
Emergence from Bankruptcy Proceedings and Subsequent Refinancing
On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 Cases were jointly administered under the caption In re California Resources Corporation, et al., Case No. 20-33568 (DRJ). We filed with the Bankruptcy Court, on July 24, 2020, the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code and, on October 8, 2020, the Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code. On October 13, 2020, the Bankruptcy Court confirmed the Plan, which was conditioned on certain items such as obtaining exit financing. The conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 on October 27, 2020 (Effective Date).
We emerged from bankruptcy on the Effective Date with a new board of directors, new equity owners and a significantly improved financial position. Under the plan of reorganization approved by the Bankruptcy Court (the Plan), all of our outstanding pre-emergence indebtedness under our credit facilities and senior notes was cancelled. At emergence, we entered into a new revolving credit facility with a $1.2 billion borrowing base and $540 million of lender commitments (Revolving Credit Facility). Our post-emergence capital structure also included a $200 million second lien term loan (Second Lien Term Loan) and $300 million of secured notes due 2027 issued by our wholly-owned subsidiary in connection with our acquisition of our partner's interest in our Elk Hills power joint venture (EHP Notes).
On January 20, 2021, we completed an offering of $600 million aggregate principal amount of 7.125% senior notes due 2026 (Senior Notes). We used the net proceeds to repay in full our Second Lien Term Loan and EHP Notes, with the remainder of the net proceeds used to repay a portion of the outstanding borrowings under our Revolving Credit Facility.
For information on the transactions which occurred pursuant to the Plan upon our emergence from Chapter 11 and fresh start accounting, see Part II, Item 8 – Financial Statements, Note 2 Chapter 11 Proceedings and Part II, Item 8 – Financial Statements, Note 3 Fresh Start Accounting.
Response to COVID-19 Pandemic and Industry Downturn
We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity.
In response to the rapid fall in commodity prices in March 2020, we ceased all field development and growth projects and shut in certain wells. We also reduced our 2020 capital budget to a level that preserves the mechanical integrity of our facilities and allows us to operate them in a safe and environmentally responsible manner. As a result, our production declined during 2020. Our 2021 capital investment program targets development of shallow oil projects in core fields and with this program, we expect total production (on a BOE basis) will decline moderately throughout 2021; however, we believe oil production will likely remain mostly flat from entry to exit. We also monetized all of our crude oil hedges in March 2020, except for certain hedges held by our joint venture with Benefit Street Partners (BSP JV), for approximately $63 million to preserve our liquidity. We began shutting in high cost, negative margin wells in March 2020 to reduce operating costs and enhance cash flow which curtailed average net production volumes by approximately 3 MBoe/d in 2020. We began returning wells to production in December 2020. As part of our operational efficiency measures, we evaluated our diverse portfolio and our various production mechanisms with a focus on wells with higher operating costs. Our teams utilized our extensive automation controls, monitored weekly well margins, and made temporary adjustments to our producing wells to ensure our operations aligned with the price environment. As a result of these actions, as well as further cost rationalization and streamlining efforts coupled with lower activity levels, our average operating expense run rate in the second half of 2020 was approximately $50 million per month compared to the first quarter of 2020 average of $65 million per month.
We have also implemented various measures to protect the health of our workforce and to support the prevention of COVID-19 at our plants, rigs, fields and administrative offices. These initiatives were implemented in accordance with the orders, regulations and guidance of federal, state and local authorities to mitigate the risks of the disease and included restricting non-essential travel and temporarily closing our administrative offices during periods of higher incidence of community spread from mid-March until mid-June 2020 and resuming again in mid-November 2020 by implementing remote work for our management team and substantially all of our office personnel, with limited return to the office in accordance with applicable protocols and restrictions on occupancy for those employees for whom remote work was not feasible. In addition, in April 2020, we implemented reduced work hours for nearly all of our office employees and reduced salaries for our management team, in each case on a temporary basis that ended in May 2020. In August 2020, we implemented organizational and operational efficiencies that resulted in a reduction of our headcount to approximately 1,100 employees. These actions were made in an effort to preserve liquidity after the deterioration of commodity prices following the outbreak of COVID-19. Our operational employees and contractors, and certain support personnel, have been classified as an essential critical infrastructure workforce by government authorities. Accordingly, these essential personnel have been authorized to continue to work in their plant, rig, field and office locations under our COVID-19 Health and Safety Plan, which includes, among other things, protocols for employee training, health self-assessment screening by workers and visitors entering our locations, reporting of illness, notification of workers and contact tracing associated with positive COVID-19 cases, self-quarantine or isolation, hygiene, wearing facial coverings, applying social distancing to minimize close contact between workers, cleaning or disinfecting workspaces and protection of emergency response personnel. We have not experienced any operational slowdowns due to COVID-19 among our workforce.
Production and Prices
Prices for oil and gas products in 2020 have been strongly influenced by the COVID-19 pandemic and by the actions of foreign producers. The COVID-19 pandemic caused an unprecedented demand collapse due to global shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices. In response, members of the OPEC and Russia agreed to carry out record oil production cuts in April 2020 to be followed by gradual incremental increases in multiple steps. In addition, U.S. oil and gas companies reduced their oil production by approximately 3 MMBbl/d in 2020 from peak production levels addressing the oversupplied market situation at the time of crisis. Due to these developing market dynamics, which include a successful OPEC+ agreement, a disciplined return of production in the U.S. and a broader, gradual return of demand, oil prices rebounded above $50 per barrel by the end of 2020. Brent oil price traded around $60 per barrel in February 2021.
Reduced demand initially caused shortages in available storage facilities globally and required many oil and gas producers to shut-in wells or curtail production. In April 2020, oil prices declined precipitously, temporarily reaching negative values for spot West Texas Intermediate (WTI) crude. From May 2020 through August 2020, oil prices began to recover as inventory levels stabilized and an easing of shelter-in-place restrictions created partial demand recovery. Prices declined again slightly in September 2020 as demand for oil dropped due to an increase in COVID-19 cases around the world. Oil demand and underlying commodity prices remain fragile as potential resurgence in new COVID-19 cases could force government authorities to re-impose mobility restrictions further impacting oil demand. The current futures forward curve for Brent crude indicates that prices may maintain current levels in the near term.
We continue to closely monitor the impact of COVID-19, which negatively impacted our business and results of operations beginning in the first quarter of 2020. The extent to which our 2021 operating results are impacted by the pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including the delivery of vaccinations, a resurgence of the pandemic or mutation of the virus and actions taken to contain it or actions taken by government authorities or other producers in response to commodity price movements, among other things. See Part I, Item 1A – Risk Factors, for further discussion regarding the impact of the pandemic and declines in commodity prices.
The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the years ended December 31, 2020, 2019 and 2018:
|November 1, 2020 - December 31, 2020||January 1, 2020 - October 31, 2020||2020||2019||2018|
| San Joaquin Basin||38 ||42 ||42 ||52 ||53 |
| Los Angeles Basin||23 ||25 ||24 ||24 ||25 |
| Ventura Basin||2 ||3 ||3 ||4 ||4 |
| Total||63 ||70 ||69 ||80 ||82 |
| San Joaquin Basin||12 ||13 ||13 ||15 ||15 |
| Ventura Basin||— ||— ||— ||— ||1 |
| Total||12 ||13 ||13 ||15 ||16 |
|Natural gas (MMcf/d)|
| San Joaquin Basin||138 ||147 ||145 ||162 ||165 |
| Los Angeles Basin||1 ||2 ||2 ||2 ||1 |
| Ventura Basin||3 ||4 ||4 ||5 ||7 |
| Sacramento Basin||23 ||21 ||21 ||28 ||29 |
| Total||165 ||174 ||172 ||197 ||202 |
Total Production (MBoe/d)(a)(b)
|103 ||112 ||111 |