Document
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ý
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2019
OR
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from_______________ to _______________
Commission file number 001-38606
BERRY CORPORATION (bry)
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation or organization)
 
81-5410470
(I.R.S. Employer Identification Number)
16000 Dallas Parkway, Suite 500
Dallas, Texas 75248
(661) 616-3900
(Address of principal executive offices, including zip code
Registrant’s telephone number, including area code):
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $0.001 per share
Trading Symbol
BRY
Name of each exchange on which registered
Nasdaq Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ¨ No ý
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 ý
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 ý   No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).                                              Yes ý   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 emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
 
Accelerated filer ¨
 
Non-accelerated filer ý
 
Smaller reporting company ¨
         Emerging Growth Company ý
 
 
 
 
 
 
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 is a shell company (as defined in Rule 12b-2 of the Act).          Yes ¨    No ý
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $575.4 million.
Shares of common stock outstanding as of January 31, 2020                             79,546,417





DOCUMENTS INCORPORATED BY REFERENCE
The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 5, 2020) will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2019 and is incorporated by reference in Part III to the extent described herein.



Table of Contents
 
 

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


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Index to Financial Statements and Supplementary Data

Part I
Items 1 and 2. Business and Properties
Effective February 18, 2020, Berry Petroleum Corporation changed its name to Berry Corporation (bry) and introduced a new logo. We believe that the name Berry Corporation (bry) is a name that better represents our progressive approach to evolving and growing the business in today’s dynamic oil and gas industry.
When we use the terms “we,” “us,” “our,” the “Company,” or similar words in this report, unless the context otherwise requires, (i) on or after the Effective Date (as defined below in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Commitments, and Contingencies”), we are referring to Berry Corporation (bry), a Delaware corporation formerly known as Berry Petroleum Corporation ("Berry Corp."), together with its subsidiary Berry Petroleum LLC, a Delaware limited liability company ("Berry LLC"), the successor company and(ii) prior to the Effective Date, we are referring to Berry LLC, as the predecessor company.
Our Company
We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived, oil reserves in conventional reservoirs.
In the aggregate, the Company’s assets are characterized by high oil content. Most of our assets are located in the oil-rich reservoirs in the San Joaquin basin of California, which has more than 150 years of production history and substantial remaining oil in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics are well understood, leading to predictable, repeatable, low geological risk and low-cost development opportunities. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. For example, we estimate the cost to drill and complete our PUD wells in California will be less than $375,000 per well. In contrast, we estimate the cost to drill and complete our PUD wells in our Rockies (Utah and Colorado) operations will average $1.5 million per well.
We also have assets in the Uinta basin in Utah and in the Piceance basin in Colorado. The Uinta basin is a mature, light-oil-prone play covering more than 15,000 square miles with significant undeveloped resources where we have high operational control and additional behind pipe potential. The Piceance basin in Colorado, which is a prolific low geologic risk natural gas play with trillions of cubic feet of natural gas in place where we produce from a conventional, tight sandstone reservoir using proven slick water stimulation techniques to increase recoveries.
As of December 31, 2019, we had estimated total proved reserves of 138 MMBoe, of which 122 MMBoe was in California. For the year ended December 31, 2019, we had average production of approximately 29.0 MBoe/d, of which approximately 87% was oil. For the three months ended December 31, 2019, we had average production of approximately 31.3 MBoe/d, of which approximately 89% was oil. In California, our average production for the year ended and the three months ended December 31, 2019 was 22.6 MBoe/d and 25.5 MBoe/d, respectively, of which 100% was oil.
We are committed to creating long-term stockholder value. We believe that the successful execution of our strategy across our extensive inventory of identified drilling opportunities with attractive full-cycle economics and stable, oil-weighed production base with low and predictable production decline rates will support our objectives to return capital to our stockholders, produce capital efficient growth, generate Levered Free Cash Flow to fund our operations while maintaining a low leverage profile through commodity price cycles. “Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less capital expenditures, interest expense and dividends. “Adjusted EBITDA” is also a non-GAAP financial measure defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items. Please see “Management’s Discussion and Analysis-“Non-GAAP Financial Measures” for reconciliations of Levered Free Cash Flow and Adjusted EBITDA to

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Index to Financial Statements and Supplementary Data

net cash provided by operating activities and of Adjusted EBITDA to net income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP.
As part of our commitment to creating long-term stockholder value, we strive to conduct our operations in an ethical, safe and responsible manner, to protect the environment and to take care of our people and the communities in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the communities in which we operate and our other stakeholders in order to realize the full potential of our resources in a timely fashion that safeguards people and the environment and complies with existing laws and regulations. We believe that the oil and gas industry will remain an important part of the energy landscape going forward and our goal is to grow our business safely and with great support for the environment, while supporting economic growth and social equity through our operations and engagement with our stakeholders
The Berry Advantage
Our strategy is focused on creating long-term stockholder value by returning capital to stockholders, producing capital-efficient growth and generating positive Levered Free Cash Flow while maintaining a low leverage profile through commodity price cycles. We generated positive Levered Free Cash Flow in 2019 when Brent oil prices ranged from $54.91 to $74.57, and averaged $64.16 for the year. Factoring in current interest, dividend and production levels, our Levered Free Cash Flow is expected to be break even at approximately $50 Brent.
We believe the following competitive strengths will allow us to successfully execute our business strategy:
Extensive inventory of low geological risk identified drilling opportunities with attractive full-cycle economics, high operational control and a stable development and production cost environment provides capital flexibility. We expect our operations to continue to generate attractive rates of return and positive Levered Free Cash Flow, which, if sustained, would allow us to continue returning capital to stockholders, sustain current production levels and fund organic growth, among other things. For example, our PUD reserves in California are projected to average single-well rates of return of approximately 50% based on the assumptions used in preparing our SEC reserves report as of December 31, 2019. We operate approximately 95% of our producing wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, a substantial majority of our acreage is currently held by production and fee interest, including 94% of our acreage in California. Our high degree of control over our properties gives us flexibility in executing our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production. Also, unlike our peers, who operate primarily in unconventional plays, our assets generally do not necessitate inventory-constrained and highly specialized equipment, which provides us relative insulation from service cost inflation pressures. Our high degree of operational control and relatively stable cost environment provide us significant visibility and understanding of our expected cash flows.
Stable, long-lived, oil-weighted conventional asset base with low and predictable production decline rates. The majority of our interests are in properties that have produced oil for decades. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally predictable, repeatable and present lower risk than unconventional resource plays. The properties are characterized by long-lived reserves with low production decline rates, a stable development cost structure and low-geologic risk developmental drilling opportunities with predictable production profiles. The nature of our assets provides us with significant capital flexibility and an ability to hedge efficiently material quantities of future expected production. For example, our PDP reserves have an estimated annual decline rate of approximately 13% to 20% in the years between 2020 and 2025 based on total PDP Boe reserves as of December 31, 2019. Based on the assumptions underlying our PUD estimates, we estimate that we will require slightly more than $11 per Boe in annual capital expenditures to keep production volumes consistent each year over the next three years.
Brent-influenced crude oil pricing advantage. California oil prices are Brent-influenced as California refiners import approximately 73% of the state’s demand from outside the state, most of which comes from OPEC

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Index to Financial Statements and Supplementary Data

and other waterborne sources. There is a closer correlation of prices in California to Brent pricing than to WTI. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California. Our highly oil-weighted production combined with a Brent-influenced California pricing dynamic has resulted, and is expected to continue to result, in strong operating margins at current commodity prices.
Simple capital structure and conservative balance sheet leverage with ample liquidity and minimal contractual obligations. Since our 2018 initial public offering ("IPO"), our capital structure has consisted of common stock and 7.0% senior unsecured notes due February 2026 (the "2026 Notes"). As of December 31, 2019, we had $391 million of available liquidity, defined as cash on hand plus availability under our reserves-based lending facility we entered into on July 31, 2017 (as amended, the “RBL Facility”). In addition, we have minimal long-term service or fixed-volume delivery commitments. This liquidity and flexibility permit us to capitalize on opportunities that may arise to grow and increase stockholder value.
Experienced, principled and disciplined management team. Our management team has significant experience operating and managing oil and gas businesses across numerous domestic and international basins, as well as reservoir and recovery types. We use our deep technical, operational and strategic management experience to optimize the value of our assets and the Company. We are focused on the principles of growing Levered Free Cash Flows as well as the value of our production and reserves. In doing so, we take a disciplined approach to development and operating cost management, field development efficiencies and the application of proven technologies and processes new to our properties in order to generate a sustained life-cycle cost advantage.
Our Business Strategy
The principal elements of our business strategy include the following:
Return capital to our stockholders. Our objective is to maintain a disciplined value creation and returns-focused approach to capital allocation in order to generate excess free cash flow. We have returned capital to our shareholders, primarily in the form of a quarterly dividend, since our first quarter as a public company and we continue to target an attractive dividend yield. Additionally, our stock repurchase program approved by our Board of Directors in December 2018 provides an additional opportunity to return value to our existing shareholders. As of December 31, 2019, we repurchased approximately 6% of our outstanding shares for approximately $50 million and in February 2020 the Board authorized us to repurchase an additional $50 million of stock. If commodity prices increase for a sustained period of time, we would consider repaying debt obligations or returning additional capital to stockholders. For a discussion of our dividend policy, as well as our stock repurchase program, please see “Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
Grow production and reserves in a capital efficient manner while producing positive internally generated Levered Free Cash Flow. We intend to allocate capital in a disciplined manner to projects that will produce predictable and attractive rates of return. We plan to direct capital to our oil-rich and low-geologic risk development opportunities while focusing on leveraging capital efficiencies across our asset base with the primary objective of internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins.
Maintain balance sheet strength and flexibility through commodity price cycles. We intend to fund our capital program while producing positive internally generated Levered Free Cash Flow. Over time, we expect to maintain low leverage through organic growth and with excess Levered Free Cash Flow. Our objective is to achieve and maintain a long-term, through-cycle leverage ratio (as defined in our RBL Facility) between 1.0x and 2.0x, or lower.

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Index to Financial Statements and Supplementary Data

Proactively and collaboratively engage in matters related to regulation, safety, the environmental and community relations. We seek to work closely with regulators and legislators throughout the rulemaking process to minimize adverse impacts that new legislation and regulations might have on our ability to maximize our resources and to mitigate adverse impacts to our permitting process. We have found constructive dialogue with legislative and regulatory agencies can help avert compliance and permitting issues. We also believe that running our operations in a manner that protects the safety and health of our employees and is in compliance with existing laws and regulations is not only the right way to run our business, but it helps us build and maintain relationships with the communities in which we operate as well as credibility with the relevant agencies governing our operations. With ultimate oversight by our Board of Directors, Environmental, Health & Safety (“EH&S”) considerations are an integral part of our day-to-day operations and are incorporated into the strategic decision-making process across our business.
Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we continue to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will continue to advance and use innovative EOR and other recovery techniques to unlock additional value and will allocate capital towards these next generation technologies where applicable. In addition, we intend to take advantage of underdevelopment in basins where we operate by expanding our geologic investigation of reservoirs on our acreage and adjacent acreage below existing producing reservoirs. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs.
Enhance future cash flow stability and visibility through an active and continuous hedging program. Our hedging strategy is designed to insulate our capital program from price fluctuations by securing price realizations and cash flows for production. We also seek to protect our operating expenses through fixed-price gas purchase agreements and other hedging contracts. We have protected a significant portion of our anticipated crude oil production realizations and gas purchases through 2020 and have begun to hedge anticipated crude oil production and gas purchases for 2021. We will review our hedging program continuously as conditions change.

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Index to Financial Statements and Supplementary Data

Our Capital Program
For the years ended December 31, 2019 and 2018 our capital expenditures were approximately $211 million and $148 million, respectively, on an accrual basis excluding acquisitions. Our 2020 anticipated capital expenditure budget is approximately $125 to $145 million, which we expect to generate significant year-over-year oil production growth in California, while holding overall production close to flat throughout the year. We reduced our 2020 capital program compared to 2019 in response to current oil market volatility and the industry's focus on returning capital to shareholders, which we have been doing since our IPO in July 2018. We have been and continue to be a market leader in returning capital to shareholders, while continuing to generate production growth. We currently anticipate oil production will be approximately 90% of total production in 2020, compared to 87% in 2019 and 82% in 2018. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2020 capital development programs with cash flow from operations and produce positive Levered Free Cash Flow, which includes continuing to target an attractive dividend yield.
The table below sets forth the current expected allocation of our 2020 capital expenditure budget by area as compared to the allocation of our 2019 capital expenditures.

2020 Budget
 
2019 Actual

 
(in millions)
California
$
113-130
 
$
192

Utah

4-5
 
 
10

Colorado

1-2
 
 
1

Corporate
 
7-8
 
 
8

Total
$
125-145
 
$
211

The amount and timing of capital expenditures is within our control and subject to our management’s discretion, and may be adjusted during the year depending on commodity prices and other factors. We retain the flexibility to defer planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the receipt and timing of required regulatory permits and approvals, the availability of necessary equipment, infrastructure and capital, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners, as well as general market conditions.
We currently expect to employ up to three drilling rigs in California during the last three quarters of 2020, and up to one rig throughout most, if not all, of the first quarter of 2020. Additionally, we currently expect to drill approximately 195 to 225 gross development wells during 2020, almost all of which will be in California for oil production. However, the execution of these plans requires certain regulatory permits and approvals, and changes in laws and regulations, including those relating to the permit review and approval process, could impact our ability to successfully execute our plans. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial condition and results of operations. Please see “Regulation of Health, Safety and Environmental Matters” for additional discussion of the laws and regulations impacting our business. For additional information about the potential risks related to our capital program, see “Item 1A. Risk Factors” and for a more detailed discussion of capital expenditures, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Program”.
In addition to capital expenditures, we also incur costs associated with retiring assets and remediating property at the end of its useful life, both due to regulatory obligations and our focus on EH&S as we develop existing fields. Most of these obligations and activities are regulated by governmental agencies. During 2019, we spent approximately $27 million in fulfilling these obligations and in 2020 we expect to spend approximately $20 million. A significant portion of these costs is a result of California's new idle well regulations which became effective in 2019 and accelerated the timing of abandonment of certain existing idle wells. In accordance with these regulations, we expect to plug and abandon a majority of our existing idle wells over the next eight years.

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Index to Financial Statements and Supplementary Data

Our Areas of Operation
Our predominant operating area is in California, and we also have operations in Utah and Colorado, which we refer to collectively as our Rockies operating area.
California
California is and has been one of the most productive oil and natural gas regions in the world. According to the U.S. Geological Survey as of 2012, the San Joaquin basin in California contained three of the 10 largest oil fields in the United States based on cumulative production and proved reserves. We have operations in two of those three fields —Midway-Sunset and South Belridge.
We also have operations in the McKittrick and Poso Creek fields in the San Joaquin basin in Kern County as well as in the Placerita Field in the Ventura basin in Los Angeles County. According to the California Geologic Energy Management Division (“CalGEM”), formerly known as the Division of Oil, Gas, and Geothermal Resources ("DOGGR") of the California Department of Conservation, approximately 74% of California’s daily oil production of 443 MBbl/d for 2018 was produced in the San Joaquin basin. We believe there are extensive existing field redevelopment opportunities in our areas of operation within the San Joaquin basin. We also believe that our California focus and strong balance sheet will allow us to take advantage of these opportunities.
We currently hold nearly 15,000 net acres in the San Joaquin and Ventura basins with a 99% average working interest, and our producing areas include:
Northwest San Joaquin operations: (i) our McKittrick Field property, which is a newer steamflood development with potential for infill and extension drilling; (ii) our South Belridge Field Hill property, which is characterized by two known reservoirs with low geological risk containing a significant number of drilling prospects, including downspacing opportunities, as well as additional steamflood opportunities; (iii) our thermal North Midway-Sunset Diatomite properties, where we utilize innovative EOR techniques to unlock significant value and maximize recoveries; and (iv) our North Midway-Sunset sandstone properties, where we use cyclic and continuous steam injection to develop these known reservoirs.
Southeast San Joaquin operations: (i) our South Midway-Sunset, properties, which are long-life, low-decline, strong-margin thermal oil properties with additional development opportunities; (ii) our Poso Creek property, which is an active mature shallow, heavy oil asset that we continue to develop across the property; and (iii) our Placerita property, which is a mature shallow, heavy oil asset with additional recompletion opportunities.
Our California proved reserves represented approximately 88% of our total proved reserves at December 31, 2019. California accounted for 22.6 MBoe/d or 78% of our average daily production for the year ended December 31, 2019 and 25.5 MBoe/d or 81% of our average daily production for the three months ended December 31, 2019.
Along with these upstream operations, we have extensive infrastructure and excess available takeaway capacity in place to support additional development in California. We produce oil from heavy crude reservoirs using steam to heat the oil so that it will flow to the wellbore for production. To help support this operation, we own and operate five natural gas cogeneration plants that produce electricity and steam. These plants supply approximately 22% of our steam needs and approximately 48% of our field electricity needs in California generally at a discount to electricity market prices. To further help offset our costs, we currently also sell surplus power produced by three of our cogeneration facilities under power purchase agreement (“PPA”) contracts with California utility companies. We also own 80 conventional steam generators to help satisfy the steam required by our operations.
In addition, we own gathering, treatment, water recycling and softening facilities, and storage facilities in California that currently have excess capacity, reducing our need to spend capital to develop nearby assets and generally allowing us to control certain operating costs. Approximately 86% of our California oil production is sold through pipeline connections, and we have contracts in place with third-party purchasers of our crude.

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Commercial petroleum development began in the San Joaquin basin in the late 1860s when asphalt deposits were mined and shallow wells were hand dug and drilled. Rapid discovery of many of the largest oil accumulations followed during the next several decades. Operations on our properties began in 1909. In the 1960s, introduction of thermal techniques resulted in substantial new additions to reserves in heavy oil fields. The San Joaquin basin contains multiple stacked benches that have allowed continuing discoveries of stratigraphic, structural and non-structural traps. Most oil accumulations discovered in the San Joaquin basin occur in the Eocene age through Pleistocene age sedimentary sections. Organic rich shales from the Monterey, Kreyenhagen and Tumey formations form the source rocks that generate the oil for these accumulations.
Rockies
Uinta Basin, Utah

Our Uinta basin operations in the Brundage Canyon, Ashley Forest and Lake Canyon areas in Utah target the Green River and Wasatch formations that produce oil and natural gas at depths ranging from 5,000 feet to 8,000 feet. We have high operational control of our existing acreage which has significant upside for additional vertical and or horizontal development and recompletions.
Our Uinta basin proved reserves represented approximately 11% of our total proved reserves at December 31, 2019 and accounted for 5.0 MBoe/d or 17% of our average daily production for the year ended December 31, 2019.
We also have extensive gas infrastructure and available takeaway capacity in place to support additional development along with existing gas transportation contracts. We have natural gas gathering systems consisting of approximately 500 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. We also own a natural gas processing plant in the Brundage Canyon area located in Duchesne County, Utah with capacity of approximately 30 MMcf/d. This facility takes delivery from gathering and compression facilities we operate. Approximately 95% of the gas gathered at these facilities is produced from wells that we operate. Current throughput at the processing plant is 16-18 MMcf/d and sufficient capacity remains for additional large-scale development drilling.
Formed during the late Cretaceous to Eocene periods, the Uinta basin is a mature, light-oil-prone play located primarily in Duchesne and Uintah Counties of Utah and covers more than 15,621 square miles. Exploration efforts immediately after the Second World War led to the first commercial oil discoveries in the Uinta basin. Oil was discovered in, and produced from fluvial to lacustrine sandstones of the Green River formation in these early discoveries. The application of improved hydraulic stimulation techniques in the mid-2000s greatly increased production from the Uinta basin. As reported by the Utah Department of Natural Resources, total Utah production more than doubled from 36 MBbl/d in 2003 to 102 MBbl/d in 2018. Approximately 84% of Utah’s production in 2018 came from the Uinta basin in Duchesne and Uintah counties.
Piceance Basin, Colorado

Our primary operating areas in the Piceance basin are Garden Gulch and North Parachute in northwestern Colorado where we target the Williams Fork formation of the Mesaverde Group and produce at depths ranging from 7,500 feet to 12,500 feet. We have utilized a proven slick water completion method that has resulted in lower costs and increased recoveries. In addition, we have infrastructure and available takeaway capacity in place to support additional development along with existing gas transportation contracts.
Our Piceance basin proved reserves represented approximately 1% of our total proved reserves at December 31, 2019 and accounted for 1.4 MBoe/d or 5% of our average daily production for the year ended December 31, 2019.
The Piceance basin is located in northwestern Colorado and is a low geologic risk gas play with trillions of cubic feet of natural gas in place. Natural gas generated from coals and carbonaceous shales in the Upper Cretaceous Mesaverde Group migrated into low permeability Mesaverde Group fluvial sandstones resulting in a basin-centered gas accumulation, or what the U.S. Geological Survey terms a “continuous petroleum accumulation.” Operators recognized

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for years that the Mesaverde Group, and the Williams Fork formation in particular, contained significant quantities of gas over a large area, but the low permeability of the reservoir sandstones made it difficult to complete economic wells. Improvements in hydraulic stimulation design and completion fluids in the 1990s and 2000s, coupled with an increase in commodity prices, led to the economic development of the gas resources in the Piceance basin.
At year end 2019, we recorded an impairment charge for these properties due to the decline in our expectations of future gas prices, as such we have no plans to drill in these properties.
Our Assets and Production Information
For the year ended December 31, 2019, we had average production of approximately 29.0 MBoe/d, of which approximately 87% was oil. In California, our average production for the year ended December 31, 2019 was 22.6 MBoe/d, of which 100% was oil.
The table below summarizes our average net daily production for the year ended December 31, 2019:
 
Average Net Daily Production(1)
for the Year Ended
 
December 31, 2019
 
December 31, 2018
 
(MBoe/d)
 
Oil (%)
 
(MBoe/d)
 
Oil (%)
California
22.6

 
100
%
 
19.7

 
100
%
Utah
5.0

 
54
%
 
5.0

 
48
%
Colorado
1.4

 
2
%
 
1.7

 
1
%
East Texas(2)

 
%
 
0.6

 
%
Total
29.0

 
87
%
 
27.0

 
82
%
__________
(1)    Production represents volumes sold during the period.
(2)    On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin


Production Data
The following table sets forth information regarding production for the years ended December 31, 2019 and 2018.
 
Year Ended
 
December 31, 2019
 
December 31, 2018
Average daily production(1)(3):
 
 
 
Oil (MBbl/d)
25.3

 
22.0

Natural gas (MMcf/d)
20.0

 
26.3

NGLs (MBbl/d)
0.4

 
0.6

Total (MBOE/d)(2)
29.0

 
27.0

__________
(1)
Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
(2)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.
(3)
On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.



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Our Development Inventory
We have an extensive inventory of low-geologic risk, high-return development opportunities. As of December 31, 2019, we identified 10,859 gross drilling locations across our asset base. For a discussion of how we identify drilling locations, please see “—Our Reserves—Determination of Identified Drilling Locations.”
We operate approximately 95% of our producing wells. In addition, a substantial majority of our acreage is currently held by production and fee interest, including 94% of our acreage in California. As of December 31, 2019, the combined net acreage covered by leases expiring in the next three years represented approximately 13% of our total net acreage of which 11% is in Utah. Our high degree of operational control, together with the large portion of our acreage that is held by production, gives us flexibility over the execution of our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production.
The following table summarizes certain information concerning our active producing and identified development assets as of December 31, 2019:
 
Acreage
 
Net Acreage Held By Production and Fee Interest(%)
 
Producing Wells, Gross(2)(3)
 
Average Working Interest (%)(3)(4)
 
Net Revenue Interest (%)(3)(5)
 
Identified Drilling Locations(6)
 
Gross
 
Net(1)
 
 
Gross
 
Net
California
18,517
 
14,144
 
94
%
 
3,014

 
99
%
 
93
%
 
10,822

 
10,785

Utah
123,665
 
92,921
 
70
%
 
943

 
95
%
 
62
%
 
37

 
29

Colorado
10,553
 
8,008
 
85
%
 
167

 
83
%
 
79
%
 

 

Total
152,735
 
115,073
 
80
%
 
4,124

 
98
%
 
90
%
 
10,859

 
10,814

__________
(1)
Represents our weighted-average interest in our acreage.     
(2)
Includes 658 steamflood and waterflood injection wells in California.
(3)
Excludes 90 wells in the Piceance basin each with a 5% working interest.
(4)
Represents our weighted-average working interest in our active wells.
(5)
Represents our weighted-average net revenue interest for the year ended December 31, 2019.
(6)
Our total identified drilling locations include approximately 1,289 gross (1,276 net) locations associated with PUDs as of December 31, 2019, including 123 gross (121 net) steamflood injection wells. Please see “—Our Reserves—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations.

Our Reserves
Reserve Data
As of December 31, 2019, we had estimated total proved reserves of 138 MBoe.
The majority of our reserves are composed of crude oil in shallow, long-lived reservoirs. As of December 31, 2019, approximately 88% of our proved reserves and approximately 96% of the PV-10 value of our proved reserves are derived from our assets in California. We also operate in the Uinta basin in Utah, a mature, light-oil-prone play with significant undeveloped resources, as well as in the Piceance basin in Colorado, a prolific natural gas play with low geologic risk.
As of December 31, 2019, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our proved reserves were approximately $1.5 billion and $1.8 billion, respectively. PV-10 is a financial measure that is not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see in “—PV-10” below.

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The tables below summarize our proved reserves and PV-10 by category as of December 31, 2019:
 
Proved Reserves as of December 31, 2019(1)
 
Oil (MMBbl)
 
Natural Gas (Bcf)
 
NGLs (MMBbl)
 
Total (MMBoe)(2)
 
% of Proved
 
% Proved Developed
 
Capex(3) ($MM)
 
PV-10(4) ($B)
PDP
61

 
39

 
1

 
68
 
49
%
 
84
%
 
54

 
1.0

PDNP
13

 

 

 
13
 
10
%
 
16
%
 
30

 
0.2

PUD
56

 
6

 

 
57
 
41
%
 
%
 
706

 
0.6

Total
130

 
45

 
1

 
138
 
100
%
 
100
%
 
790

 
1.8

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
California
122

 

 

 
122
 

 

 
747

 
1.7

__________
(1)
Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $63.15 per Bbl Brent for oil and natural gas liquids (“NGLs”) and $2.62 per MMBtu Henry Hub for natural gas at December 31, 2019. The volume-weighted average prices over the lives of the properties were estimated at $58.88 per Bbl of oil and condensate, $16.93 per Bbl of NGLs and $2.84 per Mcf of gas. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules, including adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Please see “—Our Reserves and Production Information—PV-10”.
(2)
Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(3)
Represents undiscounted future capital expenditures estimated as of December 31, 2019.
(4)
PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—Our Reserves and Production Information—PV-10”. PV-10 does not give effect to derivatives transactions.

The following table summarizes our estimated proved reserves and related PV-10 as of December 31, 2019. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton. The reserve estimates were prepared in accordance with current SEC rules and regulations regarding oil, natural gas and NGL reserve reporting. Reserves are stated net of applicable royalties.

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Proved Reserves as of December 31, 2019(1)
 
California
(San Joaquin and Ventura basins)
 
Utah
(Uinta basin)
 
Colorado
(Piceance basin)
 
Total
Proved developed reserves:
 
 
 
 
 
 
 
Oil (MMBbl)
68

 
6

 

 
74

Natural Gas (Bcf)

 
30

 
9

 
39

NGLs (MMBbl)

 
1

 

 
1

Total (MMBoe)(2)(3)
68

 
12

 
1

 
82

Proved undeveloped reserves:
 
 
 
 
 
 
 
Oil (MMBbl)
54

 
2

 

 
56

Natural Gas (Bcf)

 
6

 

 
6

NGLs (MMBbl)

 

 

 

Total (MMBoe)(3)
54

 
3

 

 
57

Total proved reserves:
 
 
 
 
 
 
 
Oil (MMBbl)
122

 
8

 

 
130

Natural Gas (Bcf)

 
36

 
9

 
45

NGLs (MMBbl)

 
1

 

 
1

Total (MMBoe)(3)
122

 
15

 
1

 
138

 
 
 
 
 
 
 
 
PV-10 ($billion)(4)
$
1.7

 
$
0.1

 
$

 
$
1.8

__________
(1)
Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $63.15 per Bbl Brent for oil and NGLs and $2.62 per MMBtu Henry Hub for natural gas at December 31, 2019. The volume-weighted average prices over the lives of the properties were $58.88 per Bbl of oil and condensate, $16.93 per Bbl of NGLs and $2.84 per Mcf. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. For more information regarding commodity price risk, please see “Item 1A. Risk Factors—Risks Related to Our Business and IndustryOil, natural gas and NGL prices are volatile and directly affect our results.
(2)
Approximately 18% of proved developed oil reserves, 0% of proved developed NGL reserves, 0% of proved developed natural gas reserves and 16% of total proved developed reserves are non-producing.
(3)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.
(4)
For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—PV-10.” PV-10 does not give effect to derivatives transactions.

PV-10
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and does not give effect to derivative transactions or estimated future income taxes. Management believes that PV-10 provides useful information to investors because it is widely used by analysts and investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

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The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2019:
 
At December 31, 2019
 
(in billions)
California PV-10
$
1.7

Utah PV-10
0.1

Colorado PV-10

Total Company PV-10
1.8

Less: present value of future income taxes discounted at 10%
(0.3
)
Standardized measure of discounted future net cash flows
$
1.5

Proved Reserves Additions
Our proved reserves in California increased 24 MMBoe, or 23% before production, resulting in a 299% replacement ratio. The decrease in the Colorado reserves of 17 MMBoe was a result of the current unfavorable gas market. The total changes to our proved reserves from December 31, 2018 to December 31, 2019 were as follows:
 
California
(San Joaquin and Ventura basins)
 
Utah
(Uinta basin)
 
Colorado
(Piceance basin)
 
Total
 
(in MMBoe)(1)
Beginning balance as of December 31, 2018
106

 
19

 
18

 
143

Extensions and discoveries
13

 

 

 
13

Revisions of previous estimates
11

 
(2
)
 
(16
)
 
(7
)
Purchases of minerals in place

 

 

 

Current year production
(8
)
 
(2
)
 
(1
)
 
(11
)
Ending balance as of December 31, 2019
122

 
15

 
1

 
138

__________
(1)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.

Extensions and Discoveries. During 2019, we added 13 MMBoe of proved reserves from extensions and discoveries principally in our California properties. These extensions included McKittrick steamflood expansions based on delineation wells drilled in 2019, Homebase Pliocene development, as well as expansion of our thermal Diatomite operations.
Revisions of Previous Estimates.
Revisions related to impairment - At year end 2019, we performed impairment tests with respect to our proved and unproved properties triggered by the persistent decline in gas prices throughout 2019. As a result, we recorded an impairment charge for our Piceance gas properties. Our revisions of previous estimates total includes the removal of 16 MMBoe of proved undeveloped reserves related to this impairment.
Revisions related to price - Product price changes affect the proved reserves we record. For example, higher prices generally increase the economically recoverable reserves in all of our operations because the extra margin extends their expected lives and renders more projects economic. Conversely, when prices drop, we experience the opposite effects.

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In 2019, our total net negative price revision was 2 MMBoe in California and 2 MMBoe in Utah. This was primarily the result of lower prices in the current commodity price environment.
Revisions related to performance - Performance-related revisions can include upward or downward changes to previous proved reserves estimates due to the evaluation or interpretation of recent geologic, production decline or operating performance data. In 2019, there were positive technical revisions of approximately 13 MMBoe primarily due to improved base performance and redevelopment in our thermal Diatomite area.
Current Year Production - Please refer to “Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCertain Operating and Financial Information” for discussion of our current year production.
Proved Undeveloped Reserves Changes
Our California proved undeveloped reserves increased 25 MMBoe in 2019 mainly due to extensions and technical revisions. These increases were offset by reclassifications to proved developed reserves of 10 MMboe. The Colorado proved undeveloped reserves were fully written down due to the worsening gas market there. The total changes to our proved undeveloped reserves from December 31, 2018 to December 31, 2019 were as follows:
 
California
(San Joaquin and Ventura basins)
 
Utah
(Uinta basin)
 
Colorado
(Piceance basin)
 
Total
 
(in MMBoe)(1)
Beginning balance as of December 31, 2018
40

 
1

 
14

 
55

Extensions and discoveries
12

 

 

 
12

Revisions of previous estimates
13

 
1

 
(14
)
 

Reclassifications to proved developed
(10
)
 

 

 
(10
)
Ending balance as of December 31, 2019
55

 
2

 
0

 
57

__________
(1)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.

Extensions and Discoveries. During 2019, we added 12 MMBoe of proved undeveloped reserves from extensions and discoveries due to drilling unproven locations in the Midway Sunset and McKittrick fields.
Revisions of previous estimates.
Revisions related to price - In 2019, our net negative price revision on proved undeveloped reserves were approximately 1 MMBoe in California, which was primarily the result of lower prices due to the current commodity price environment. Oil prices have decreased by 12%, and gas prices have decreased by 15%.
Revisions related to performance - In 2019, our net positive performance-related revision on proved undeveloped reserves was 13 MMBoe in California which resulted primarily from our thermal Diatomite area, and 1 MMBoe due to the improved type curve performance in our Uinta basin resulting from 2019 drilling activity.
Reclassifications to proved developed. Through the 2019 drilling program, we transferred 10 MMBoe of proved undeveloped reserves to the proved developed category in California. As a result, we converted 23% of our beginning-of-the year inventory of proved undeveloped reserves, spending approximately $74 million of capital. The conversion rate reflected a gradual increase in capital spend from the lower pace of development in the prior year. At average Brent oil prices between $60 to $65 per barrel and average Henry Hub gas prices of at least $2.60 per mcf, we expect to have

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Index to Financial Statements and Supplementary Data

sufficient future capital to develop our proved undeveloped reserves at December 31, 2019 within five years. Prices substantially below these levels for a prolonged period of time may require us to reduce expected capital expenditures over the next five years, potentially impacting either the quantity or the development timing of proved undeveloped reserves. Our year-end proved undeveloped reserves are determined in accordance with SEC guidelines for development within five years. We believe we have management's commitment and sufficient future capital to develop all of our proved undeveloped reserves. 
Reserves Evaluation and Review Process
Independent engineers, DeGolyer and MacNaughton (“D&M”), prepared our reserve estimates reported herein. The process performed by D&M to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by us. When preparing the reserve estimates, D&M did not independently verify the accuracy and completeness of the information and data furnished by us with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of D&M's work, something came to their attention that brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their related questions. The estimates of reserves conform to SEC guidelines, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost, operating expense and commodity revenue data.
D&M also prepared estimates with respect to reserves categorization, using the definitions of proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
Our internal control over the preparation of reserves estimates is designed to provide reasonable assurance regarding the reliability of our reserves estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by Kurt Neher, Executive Vice President of Business Development, who has a Masters in Geology from the University of South Carolina and a Bachelors in Geology from Carleton College, and more than 32 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, and presented to our board of directors. Within D&M, the technical person primarily responsible for reviewing our reserves estimates was Gregory K. Graves, P.E. Mr. Graves is a Registered Professional Engineer in the State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and has in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum Engineering.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured exactly. For more information, see “Item 1A. Risk Factors—Risks Related to Our Business and IndustryEstimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.

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Index to Financial Statements and Supplementary Data

Determination of Identified Drilling Locations
Proven Drilling Locations

Based on our reserves report as of December 31, 2019, we have approximately 1,289 gross (1,276 net) drilling locations attributable to our proved undeveloped reserves, compared to 1,071 gross (1,058 net) as of December 31, 2018. The increases in drilling locations attributable to our proved undeveloped reserves is primarily due to development in the Homebase and McKittrick fields. We use production data and experience gained from our development programs to identify and prioritize development of this proven drilling inventory. These drilling locations are included in our inventory only after they have been evaluated technically and are deemed to have a high likelihood of being drilled within a five-year time frame. As a result of technical evaluation of geologic and engineering data, it can be estimated with reasonable certainty that reserves from these locations 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.
Unproven Drilling Locations

We have also identified a multi-year inventory of 9,570 gross (9,379 net) drilling locations as of December 31, 2019, compared to 5,959 gross (5,604 net) drilling locations as of December 31, 2018. Our unproven drilling locations are specifically identified on a field-by-field basis considering the applicable geologic, engineering and production data. We analyze past field development practices and identify analogous drilling opportunities taking into consideration historical production performance, estimated drilling and completion costs, spacing and other performance factors. These drilling locations primarily include (i) infill drilling locations, (ii) additional locations due to field extensions or (iii) potential IOR and EOR project expansions, some of which are currently in the pilot phase across our properties, but have yet to be determined to be proven locations. We believe the assumptions and data used to estimate these drilling locations are consistent with established industry practices based on the type of recovery process we are using.
We plan to analyze our acreage for exploration drilling opportunities at appropriate levels. We expect to use internally generated information and proprietary models consisting of data from analog plays, 3-D seismic data, open hole and mud log data, cores and reservoir engineering data to help define the extent of the targeted intervals and the potential ability of such intervals to produce commercial quantities of hydrocarbons.
Well Spacing Determination

Our well spacing determinations in the above categories of identified well locations are based on actual operational spacing within our existing producing fields, which we believe are reasonable for the particular recovery process employed (i.e., primary, waterflood and thermal EOR). Spacing intervals can vary between various reservoirs and recovery techniques. Our development spacing can be less than one acre for a thermal steamflood development in California and greater than ten acres for a primary gas expansion development in our Piceance asset in Colorado.
Drilling Schedule

Our identified drilling locations have been scheduled as part of our current multi-year drilling schedule or are expected to be scheduled in the future. However, we may not drill our identified sites at the times scheduled or at all. We view the risk profile for our prospective drilling locations and any exploration drilling locations we may identify in the future as being higher than for our other proved drilling locations.
Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals, available transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. For a discussion of the risks associated with our drilling program, see “Item 1A. Risk Factors—Risks Related to Our Business and IndustryWe may not drill our identified sites at the times we scheduled or at all.

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Index to Financial Statements and Supplementary Data

The table below sets forth our proved undeveloped drilling locations and unproven drilling locations as of December 31, 2019.
 
PUD Drilling Locations
(Gross)
 
Unproven Drilling Locations (Gross)
 
Total Drilling Locations (Gross)
 
Oil and Natural Gas Wells
 
Injection
Wells
 
Oil and Natural Gas Wells
 
Injection
Wells
 
Oil and Natural Gas Wells
 
Injection
Wells
California
1,129

 
123

 
8,099

 
1,471

 
9,228

 
1,594

Utah
37

 

 

 

 
37

 

Colorado

 

 

 

 

 

Total Identified Drilling Locations
1,166

 
123

 
8,099

 
1,471

 
9,265

 
1,594


The following tables sets forth information regarding production volumes for fields with equal to or greater than 15% of our total proved reserves for each of the periods indicated:
 
Berry Corp.
(Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
SJV Midway Sunset Field
 
 
 
 
 
 
 
 
Total production(1):
 
 
 
 
 
 
 
 
Oil (MBbls)
5,543

 
4,495

 
3,560

 
 
693

Natural gas (Bcf)

 

 

 
 

NGLs (MBbls)

 

 

 
 

Total (MBoe)(2)
5,543

 
4,495

 
3,560

 
 
693

 
Berry Corp.
(Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
SJV Belridge Hill(3)
 
 
 
 
 
 
 
 
Total production(1):
 
 
 
 
 
 
 
 
Oil (MBbls)
1,312

 
1,196

 
609

 
 
35

Natural gas (Bcf)

 

 

 
 

NGLs (MBbls)

 

 

 
 

Total (MBoe)(2)
1,312

 
1,196

 
609

 
 
35

 
Berry Corp.
(Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
Piceance
 
 
 
 
 
 
 
 
Total production(1):
 
 
 
 
 
 
 
 
Oil (MBbls)
*
 
*
 
14

 
 
2

Natural gas (Bcf)
*
 
*
 
3.6

 
 
0.8

NGLs (MBbls)
*
 
*
 

 
 

Total (MBoe)(2)
*
 
*
 
610

 
 
138

__________
*
Represented less than 15% of our total proved reserves for the periods indicated.
(1)
Production represents volumes sold during the period.

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Index to Financial Statements and Supplementary Data

(2)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1.
(3)
In July 2017, we acquired the remaining 84% working interest in the South Belridge Hill property located in Kern County, California, in which we previously owned a 16% working interest.

Productive Wells
As of December 31, 2019, we had a total of 3,666 gross (3,541 net) productive wells (including 610 gross and net steamflood and waterflood injection wells), approximately 95% of which were oil wells. Our average working interests in our productive wells is approximately 98%. Many of our oil wells produce associated gas and some of our gas wells also produce condensate and NGLs.
The following table sets forth our productive oil and natural gas wells (both producing and capable of producing) as of December 31, 2019.
 
California
(San Joaquin and Ventura basins)
 
Utah
(Uinta basin)
 
Colorado
(Piceance basin)
 
Total
Oil
 
 
 
 
 
 
 
Gross(1)
2,504

 
986

 

 
3,490
Net(2)
2,479

 
937

 

 
3,416
Gas
 
 
 
 
 
 

Gross(1)

 

 
176

 
176
Net(2)

 

 
125

 
125
__________
(1)
The total number of wells in which interests are owned. Includes 610 steamflood and waterflood injection wells in California.
(2)
The sum of fractional interests.

Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2019.
 
California
(San Joaquin and Ventura basins)
 
Utah and Other
(Uinta and Piceance basins)
 
Total
Developed(1)
 
 
 
 
 
Gross(2)
9,835
 
94,268
 
104,103
Net(3)
9,289
 
72,103
 
81,392
Undeveloped(4)
 
 
 
 
 
Gross(2)
8,682
 
39,950
 
48,632
Net(3)
4,855
 
28,827
 
33,682
__________
(1)
Acres spaced or assigned to productive wells.
(2)
Total acres in which we hold an interest.
(3)
Sum of fractional interests owned based on working interests or interests under arrangements similar to production sharing contracts.
(4)
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the acreage contains proved reserves.


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Index to Financial Statements and Supplementary Data

Participation in Wells Being Drilled
As of December 31, 2019, we were not participating in any development or exploratory wells. We were participating in 14 steamflood and waterflood pressure maintenance projects - 12 steamflood projects and one waterflood project were located in the San Joaquin basin, and one waterflood project was located in the Uinta basin.
Drilling Activity
The following table shows the net development wells we drilled during the periods indicated. We did not drill any exploratory wells during the periods presented. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.
 
California
(San Joaquin and Ventura basins)
 
Utah
(Uinta basin)
 
Colorado
(Piceance basin)
 
Total
2019
 
 
 
 
 
 
 
Oil(2)
335

 
3

 

 
338

Natural Gas

 

 

 

Dry

 

 

 

2018
 
 
 
 
 
 
 
Oil(1)
224

 
8

 

 
232

Natural Gas

 

 

 

Dry

 

 

 

2017
 
 
 
 
 
 
 
Oil(1)
124

 

 

 
124

Natural Gas

 

 

 

Dry

 

 

 

__________
(1)
Includes injector wells.
(2)
Includes 50 wells that had not yet been connected to gathering systems in California.

Delivery Commitments
We have contractual agreements to provide gas volumes for transportation, processing and sales, some of which specify fixed and determinable quantities and all of which were in Utah. As of December 31, 2019, the volumes contracted to be delivered were approximately 7,170 MMBtu/d of gas beginning in 2020 and will decrease over time to 4,560 MMBtu/d in 2022. We have significantly more production capacity than the amounts committed and have the ability to secure additional volumes in case of a shortfall.

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Methods of Recovery and Marketing Arrangements
We seek to be the operator of our properties so that we can develop and implement drilling programs and optimization projects that not only replace production but add value through reserve and production growth and future operational synergies. We have an average of 98% working interest and 95% operating control in our properties.
Our California operations are primarily focused on the thermal Sandstones, thermal Diatomite and Hill Diatomite, development areas. We also have operations in the Uinta basin in Utah and Piceance in Colorado, as noted in the following table.
 
 
 
 
 
 
 
 
 
 
Gross Drilling Locations(1)
State
 
Project Type
 
Well Type
 
Completion Type
 
Recovery Mechanism
 
Total
California
 
Thermal Sandstones
 
Vertical / Horizontal
 
Perforation/Slotted liner/gravel pack
 
Continuous and cyclic steam injection
 
6,143

California
 
Thermal Diatomite
 
Vertical
 
Short interval perforations
 
High-pressure cyclic steam injection
 
3,198

California
 
Hill Diatomite (non-thermal)
 
Vertical
 
Hydraulic stimulation, low intensity pin point
 
Pressure depletion augmented with water injection
 
1,481

Utah
 
Uinta
 
Vertical / Horizontal
 
Low intensity hydraulic stimulation
 
Pressure depletion
 
37

Colorado
 
Piceance
 
Vertical
 
Proppantless slick water stimulation
 
Pressure depletion
 

Total
 
 
 
 
 
 
 
 
 
10,859

__________
(1)
We had 1,289 gross (1,276 net) locations associated with PUDs as of December 31, 2019 including 123 gross (121 net) steamflood injection wells. Of those 1,289 gross PUD locations, 1,252 are associated with projects in California, 37 are associated with the Uinta basin. Please see “—Our Reserves —Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations. During the year ended December 31, 2019, we drilled 292 gross (292 net) wells that were associated with PUDs at December 31, 2018, including 25 gross (25 net) steamflood injection wells.

Thermal Recovery
Most of our assets in California consist of heavy crude oil, which requires heat, supplied in the form of steam, injected into the oil producing formations to reduce the oil viscosity, thereby allowing the oil to flow to the wellbore for production. We have cyclic and continuous steam injection projects in the San Joaquin and Ventura basins, primarily in Kern County and in fields such as Midway-Sunset, Poso Creek, McKittrick, South Belridge and Placerita. This technique has many years of demonstrated success in thousands of wells drilled by us and others. Historically, we start production from heavy oil reservoirs with cyclic injection and then expand operations to include continuous injection in adjacent wells. We intend to continue employing both recovery techniques as long as a favorable oil to gas price spread exists. Full development of these projects typically takes multiple years and involves upfront infrastructure construction for steam and water processing facilities and follow on development drilling. These thermal recovery projects are generally shallower in depth (300 to 1,200 ft) than our other programs and the wells are relatively inexpensive to drill and complete at approximately $210,000 per well. Therefore, we can normally implement a drilling program quickly with attractive rates of return.
Cogeneration Steam Supply and Conventional Steam Generation
We produce oil from heavy crude reservoirs using steam to heat the oil so that it will flow to the wellbore for production. To assist in this operation, we own and operate five natural gas burning cogeneration plants that produce electricity and steam: (i) a 38 MW facility (“Cogen 38”), an 18 MW facility (“Cogen 18”) and a 5 MW facility (“Pan Fee Cogen”), each located in the Midway-Sunset Field, (ii) another 5MW facility (“21Z Cogen”) located in the McKittrick Field, and (iii) a 42 MW facility (“Cogen 42”) located in the Placerita Field. Cogeneration plants, also referred to as combined heat and power plants, use hot turbine exhaust to produce steam while generating electrical

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power. This combined process is more efficient than producing power or steam separately. For more information please see “—Electricity.” and “Item 1A. Risk Factors—Risks Related to Our Business and Industry—We are dependent on our cogeneration facilities to produce steam for our operations. Contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.
We own 80 fully permitted conventional steam generators. The number of generators operated at any point in time is dependent on (i) the steam volume required to achieve our targeted injection rate and (ii) the price of natural gas compared to our oil production rate and the realized price of oil sold. Ownership of these varied steam generation facilities allows for maximum operational control over the steam supply, location and, to some extent, the aggregated cost of steam generation. The natural gas we purchase to generate steam and electricity is primarily based on California price indexes, and in some cases includes transportation charges.
Hydraulic Stimulation
Hydraulic stimulation is an important and common practice that is used to stimulate production of hydrocarbons from tight geologic formations. The process involves the injection of water, sand and trace amounts of chemicals under pressure into formations to enhance the permeability of the surrounding rock and stimulate production. Our California hydraulic stimulation projects use significantly lower fluid and sand volumes than is typical in other areas. For example, we expect to use approximately 150 thousand gallons of water per well for our Hill hydraulic stimulations compared to a median of nearly 4 million gallons for horizontal, unconventional shale wells hydraulically stimulated in the United States in 2014. Similarly, we expect to use only about 325 thousand pounds of sand per Hill well compared to a nationwide average of over 4 million pounds of sand per well in 2015. We use low-volume hydraulic reservoir stimulation in the San Joaquin basin to stimulate our non-thermal Diatomite reservoir at the Hill property. We applied this technique in 2019 and plan to continue this stimulation method on our inventory of Hill non-thermal Diatomite development wells.
We use more traditional hydraulic stimulation techniques to complete our wells in the Piceance basin. However, in this area, we use a more advanced technique known as “proppantless stimulation” to stimulate the reservoir with water and no proppant, such as sand.
Marketing Arrangements
We market crude oil, natural gas, NGLs, gas purchasing and electricity.

Crude Oil. Approximately 86% of our California crude oil production is connected to California markets via crude oil pipelines. We generally do not transport, refine or process the crude oil we produce and do not have any long-term crude oil transportation arrangements in place. California oil prices are Brent-influenced as California refiners import approximately 73% of the state’s demand from OPEC countries and other waterborne sources. This dynamic has led to periods, including recent years, where the price for the primary benchmark, Midway-Sunset, a 13° API heavy crude, has been equal to or exceeded the price for WTI, a light 40° API crude. Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production and low transportation costs, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash margins in California. Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to purchaser-posted prices for the producing area. As of December 31, 2019, all of our oil production was sold under short-term contracts. The waxy quality of oil in Utah has historically limited sales primarily to the Salt Lake City market, which is largely dependent on the supply and demand of oil in the area. The recent success of a tight oil play in the basin has increased supply and put downward pressure on physical oil prices. Due to these circumstances, we are endeavoring to sell our crude to markets outside the basin. Export options to other markets via rail are available and have been used in the past, but are comparatively expensive. We also entered into oil hedges to protect our operating expenses from price fluctuations.
Natural Gas. Our natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area. Our natural gas production is sold to purchasers under seasonal spot price or index contracts. As of December 31, 2019, all of our natural gas and NGL production was sold under short-term contracts at market-sensitive or spot prices. In certain circumstances, we have

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entered into natural gas processing contracts whereby the residual natural gas is sold under short-term contracts but the related NGLs are sold under long-term contracts. In all such cases, the residual natural gas and NGLs are sold at market-sensitive index prices.
NGLs. We do not have long-term or long-haul interstate NGL transportation agreements. We sell substantially all of our NGLs to third parties using market-based pricing. Our NGL sales are generally pursuant to processing contracts or short-term sales contracts. The relatively small volumes of condensate produced in Colorado are sold under market-based short-term contracts.
Gas Purchasing. We enter into hedges for gas purchases to protect our operating expenses from price fluctuations.
Electricity Generation. Our cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. The total nameplate electrical generation capacity of our five cogeneration facilities, which are centrally located on certain of our oil producing properties, is approximately 108 MW. The steam generated by each facility is capable of being delivered to numerous wells that require steam for our EOR processes. The main purpose of the cogeneration facilities is to reduce the steam and electricity costs in our heavy oil operations.
Electricity and steam produced from our Pan Fee and 21Z cogeneration facilities are used solely for field operations.

For the year ended December 31, 2019, we sold approximately 1,700 megawatt-hours (“MWhs”) per day of cogen power into the grid and consumed approximately 700 MWhs per day of cogen power for lease operations. The five cogeneration facilities produced an average of approximately 36,000 barrels of steam per day. Contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.
Electricity Sales Contracts. We sell electricity produced by three of our cogeneration facilities under long-term PPAs approved by the California Public Utilities Commission (the “CPUC”) to two California investor-owned utilities, Southern California Edison Company (“Edison”) and Pacific Gas and Electric (“PG&E”). These PPAs expire in various years between 2021 and 2026.
Principal Customers
For the year ended Year Ended December 31, 2019, sales to Andeavor, Phillips 66 and Kern Oil & Refining accounted for approximately 36%, 24%, and 13% respectively, of our sales. At December 31, 2019, trade accounts receivable from three customers represented approximately 40%, 17% and 11% of our receivables.
If we were to lose any one of our major oil and natural gas purchasers, the loss could cease or delay production and sale of our oil and natural gas in that particular purchaser’s service area and could have a detrimental effect on the prices and volumes of oil, natural gas and NGLs that we are able to sell. For more information related to marketing risks, see “Item 1A. Risk Factors—Risks Related to Our Business and Industry”.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a preliminary review of the title to our properties at the time of acquisition. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. We do not commence drilling operations on a property until we have cured known title defects on such property that are material to the project. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations, or net profits interests.

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Competition
The oil and natural gas industry is highly competitive. We encounter strong competition from other companies, including independent operators in acquiring properties, contracting for drilling and other related services, and securing trained personnel. We also are affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. The lower-cost, commoditized nature of our equipment and service providers partially insulates us from the cost inflation pressures experienced by producers in unconventional plays. We are unable to predict when, or if, such shortages may occur or how they would affect our drilling program. For more information regarding competition and the related risks in the oil and natural gas industry, please see “Item 1A. Risk Factors—Risks Related to Our Business and IndustryCompetition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.
We also face indirect competition from alternative energy sources, such as wind or solar power, and these alternative energy sources could become even more competitive as future legislation and regulation as California and the federal government develops renewable energy and climate-related policies.
Seasonality
Seasonal weather conditions can impact our drilling and production activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may have been and in the future may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires and rain.
Natural gas prices can fluctuate based on seasonal and other market-related impacts. We purchase significantly more gas than we sell to generate steam and electricity in our cogeneration facilities for our producing activities. As a result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of this exposure by selling excess electricity from our cogeneration operations to third parties. The pricing of these electricity sales is closely tied to the purchase price of natural gas. We also hedge a significant portion of the gas we expect to consume.
Regulation of Health, Safety and Environmental Matters
Like other companies in the oil and gas industry, our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations:
Establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, and attainment plans to meet those regional standards, which may significantly restrict development, economic activity and transportation in the region;
require the acquisition of various permits before drilling, workover production, underground fluid injection, enhanced oil recovery methods, or waste disposal commences;
require notice to stakeholders of proposed and ongoing operations;
require the installation of expensive safety and pollution control equipment—such as leak detection, monitoring and control systems—to prevent or reduce the release or discharge of regulated materials into the air, land, surface water or groundwater;
restrict the types, quantities and concentration of various regulated materials, including oil, natural gas, produced water or wastes, that can be released into the environment in connection with drilling and production activities, and impose energy efficiency or renewable energy standards on us or users of our products;

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limit or prohibit drilling activities on lands located within coastal, wilderness, wetlands, groundwater recharge or endangered species inhabited areas, and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources, and require the dedication of surface acreage for habitat conservation;
establish waste management standards or require remedial measures to limit pollution from former operations, such as pit closure, reclamation and plugging and abandonment of wells or decommissioning of facilities;
impose substantial liabilities for pollution resulting from operations or for preexisting environmental conditions on our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state, and private lands or leases, including preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.
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 approval of projects, 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.
In April 2019 new idle well regulations went into effect in California, which includes a comprehensive well testing regime to prevent leaks, a compliance schedule for testing or plugging and abandoning idle wells, the collection of data necessary to prioritize testing and sealing idle wells, requirements for a long-term idle well management plan, an engineering analysis for each well idled 15 years or longer, and requirements for active observation wells. In California, an idle well is one that has not been used for two years or more and has not yet been permanently sealed pursuant to CalGEM regulations. We have submitted our idle well management plan to meet our obligations.
CalGEM’s predecessor also finalized new Underground Injection Control (“UIC”) regulations, effective April 2019, which affects two types of wells: (i) those that inject water or steam for enhanced oil recovery and (ii) those that return the briny groundwater that comes up from oil formations during production. The key regulations include stronger testing requirements designed to identify potential leaks, increased data requirements to ensure proposed projects are fully evaluated, continuous well pressure monitoring, requirements to automatically cease injection when there is a risk to safety or the environment, and requirements to disclose chemical additives for injection wells close to water supply wells. Our California development and production activities are subject to UIC regulations.
Also, in 2019, the Governor of California signed AB 1057, legislation that required state agencies to review emissions from idle and abandoned wells, evaluate plugging and abandonment and restoration costs and associated bonding requirements. This legislation also 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. 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.
Additionally, 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

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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 (“PALs”) for underground injection 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 January 2020, CalGEM issued a formal notice to operators, including us, that they had issued restrictions imposing a moratorium to prohibit new underground oil-extraction wells from using high-pressure cyclic steaming process. Only our undeveloped thermal diatomite assets are currently impacted by the moratorium.
CalGEM currently requires an operator to identify the manner in which CEQA has been satisfied prior to issuing various state permits or approval of projects, typically through either an environmental impact review (“EIR”) 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 (“Kern County EIR”) certified by the Kern County Board of Supervisors in 2015. A group of plaintiffs challenged the Kern County EIR and on February 25, 2020, the California Fifth District Court of Appeals issued a ruling that invalidates a portion of the Kern County EIR, effective 30 days after entry of the ruling, until Kern County makes certain revisions to the Kern County EIR and recertifies it (“Kern County Ruling”). Other state agencies, including CalGEM, have relied on the Kern County EIR to satisfy the CEQA requirements in connection with permitting and project approval decisions for oil and gas projects in unincorporated Kern County. We cannot predict how long it will take Kern County to recertify the Kern County EIR or to conduct a new EIR, either of which could ultimately result in the imposition of more onerous permit application requirements and limits on exploration and production activities. It is not yet known how Kern County will resolve this issue, or how long it will take to do so, and we cannot predict how long it will take or what the requirements and costs will be to obtain new permits and project approvals in the interim. It is also not yet known whether there will be significant delays or a pause in the issuance of new permits and approvals in unincorporated Kern County pending resolution of this issue. While the near- and longer- term impacts of the Kern County Ruling on oil and gas activities in Kern County are not yet fully known, we are actively monitoring Kern County’s response, considering the potential impacts to the permitting process, and evaluating the potential impact to our operations. We do not currently expect the Kern County Ruling to materially affect our plans and operations in Kern County as the ruling does not invalidate existing permits.
Our 2019 results were not significantly impacted by the moratorium and we currently do not expect our 2020 results to be impacted by the moratorium. Our current 2020 development and production plans do not require new high–pressure cyclic steam injection and the moratorium does not impact existing production or previously approved permits. Our 2020 plans anticipate primarily thermal sandstone development, which do not require us to use a high–pressure cyclic steam steaming process. However, our 2020 plans may be impacted by existing and pending regulatory changes or other government activity impacting the timing of, and conditions imposed on, required permits and approvals.
With the changes in the UIC regulations and its impact on the permitting process, we experienced delays in obtaining the permits required to continue our planned drilling operations over the latter half of 2019 and into 2020. In late 2019 and in early 2020 we discontinued two drilling rigs and we are currently operating one rig. We are actively reviewing the UIC regulatory developments and considering the potential impacts of the Kern County Ruling, as well as our internal processes. As part of a contingency plan, we are preparing our internal resources to support a more time-intensive and burdensome permitting application process and the potential environmental impact review requirements to mitigate the impact to our development and production plans. If we are unable to obtain the required permits on a timely basis or at all, we may not be able to continue operating this one rig or to redeploy the other two as planned and we may have to change our strategy and plans, which could adversely affect our financial and operating results.
Existing and potential future laws, rules and regulations may restrict the production rate of oil, natural gas and NGLs below the rate that would otherwise be possible. Additionally, the regulatory burden on the industry increases the cost of doing business and consequently may have an adverse effect upon capital expenditures, earnings or competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and

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prospects. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on operations. For more information related to regulatory risks, see “Item 1A. Risk Factors—Risks Related to Our Business and Industry”.
The environmental laws and regulations applicable to us and our operations include, among others, the following U.S. federal laws and regulations:
Clean Air Act (the “CAA”), which governs air emissions;
Clean Water Act (the “CWA”), which governs discharges to and excavations within the waters of the United States;
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous substances have been released into the environment (commonly known as “Superfund”);
The Oil Pollution Act of 1990, which amends and augments the CWA and imposes certain duties and liabilities related to the prevention of oil spills and damages resulting from such spills;
Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures;
National Environmental Policy Act (“NEPA”), which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands;
Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste;
SDWA, which governs the underground injection and disposal of wastewater; and
U.S. Department of Interior regulations, which regulate oil and gas production activities on federal lands and impose liability for pollution cleanup and damages.
Various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGL, including imposing production taxes and requirements for obtaining drilling permits. Our planned capital expenditures depend on a variety of factors, including but not limited to the receipt and timing of required regulatory permits and approvals. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial condition and results of operations. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of resources. States may regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulations, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGLs that may be produced from our wells and to limit the number of wells or locations we can drill. The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal opportunity employment.
We believe that compliance with currently applicable environmental laws and regulations is unlikely to have a material adverse impact on our business, financial condition, results of operations or cash flows. However, we cannot guarantee this will always be the case given the historical trend of increasingly stringent environmental regulations. Future regulatory issues that could impact us include new rules or legislation, or the reinterpretation of existing rules or legislation, relating to the items discussed below.

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Climate Change
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases (“GHGs”) as well as to restrict or eliminate such future emissions. As a result, our oil and natural gas exploration and production operations are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the U.S. Environmental Protection Agency (“EPA”) has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the U.S. Department of Transportation, (“DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, California, through the California Air Resources Board (“CARB”) has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented low carbon fuel standard (“LCFS”) and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado.
In September 2018, California adopted a law committing California , the fifth largest economy in the world, to the use of 100% zero-carbon electricity by 2045, and the Governor of California also signed an executive order committing California to total economy-wide carbon neutrality by 2045. We cannot predict how these various laws, regulations and orders may ultimately affect our operations. However, these initiatives could result in decreased demand for the oil, natural gas, and NGLs that we produce, and therefore adversely effect our revenues and results of operations.
At the international level, there is a non-binding agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. Although the United States has announced its withdrawal from such agreement, effective November 4, 2020, several U.S. states and local governments have announced their intention to adhere to the goals of the Paris Agreement.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates seeking the office of the President of the United States in 2020. Two critical declarations made by one or more candidates running for the Democratic nomination for President include threats to take actions banning hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties. Our operations involve the use of hydraulic fracturing activities and we also have operations on federal lands under the jurisdiction of the U.S. Bureau of Land Management (“BLM”). Other actions that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as the reversal of the United States’ withdrawal from the Paris Agreement in November 2020.

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Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but withheld material information from their investors by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years by environmental activists, proponents of the international Paris Agreement, and other groups concerned about climate change to restrict fossil fuel producers’ access to capital. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers such as ourselves or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. Moreover, there are increasing risks to operations resulting from the potential physical impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
For more information, please see “Item 1A. Risk Factors—Risks Related to Our Business and Industry—Concerns about climate change and other air quality issues may affect our operations or results;” and “—Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for the oil and natural gas we produce.”
Hydraulic Stimulation
Hydraulic stimulation is an important and common practice that is used to stimulate production of hydrocarbons from tight geologic formations. The process involves the injection of water, sand and trace amounts of chemicals under pressure into formations to enhance the permeability of the surrounding rock and stimulate production. Recently, as part of their oil and natural gas regulatory programs, state regulators have overseen hydraulic stimulation operations in more detail. However, the EPA has asserted federal regulatory authority pursuant to the federal SDWA over certain hydraulic stimulation activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic stimulation, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic stimulation operations to publicly owned wastewater treatment plants. The BLM previously issued regulations regarding the public disclosure of chemicals used in stimulation treatments, well construction and integrity, and management of waste fluids resulting from hydraulic fracturing activities on federal and Tribal lands. While the BLM rescinded these regulations in 2017, the rescission is subject to ongoing legal challenge. If the rule is reinstated, the outcome of this litigation could materially impact our operations in the Uinta basin and other areas. In addition, from time to time legislation has been introduced before Congress that would provide for federal regulation of hydraulic stimulation and would require disclosure of the chemicals used in the stimulation process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic stimulation operations as well as various restrictions on those

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operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.
There may be other attempts to further regulate hydraulic stimulation under the SDWA, the Toxic Substances Control Act and/or other regulatory mechanisms. In December 2016, the EPA released its final report on a wide ranging study on the effects of hydraulic stimulation on water resources. While no widespread impacts from hydraulic stimulation were found, the EPA identified a number of activities and factors that may have increased risk for future impacts.
Moreover, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could restrict hydraulic stimulation in certain circumstances or otherwise impose enhanced permitting, fluid disclosure, or well construction requirements on hydraulic stimulation activities. For example, in Colorado, there have been several initiatives underway to limit or ban crude oil and natural gas exploration, development or operations. In April 2019, Colorado adopted Senate Bill 19-181 (“SB 181”), which makes sweeping changes in Colorado oil and gas law, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission (“COGCC”) to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with SB 181. Additionally, activist groups have submitted new ballot proposals for the 2020 election year, including proposals for increased drilling setbacks and increased bonding requirements. Separately, in California, Assembly Bill 345 was introduced but failed to advance in the California Legislature to impose a statewide setback distance of 2,500 feet between certain oil and natural gas operations and residences, schools and healthcare facilities. In January 2020, the State Assembly passed an amended version of AB 345 that, if passed by the State Senate and signed by the Governor, would require CalGEM, to adopt a land use setback in its rulemaking by July 2022. As amended, the bill no longer specifies a mandatory setback distance, but would require CalGEM to consider a 2,500 foot setback as well as enhanced monitoring and maintenance requirements.
As described above, the regulation or prohibition of hydraulic stimulation is the subject of significant political activity in a number of jurisdictions, some of which have resulted in tighter regulation including recognition of local government authority to implement such restrictions. Many of these restrictions are being challenged in court cases. If new laws or regulations that significantly restrict hydraulic stimulation are adopted, such laws could make it more difficult or costly for us to perform work to stimulate production from tight formations or otherwise impact the value of our assets. In addition, any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect our revenues, results of operations and net cash provided by operating activities.
Additionally, hydraulic stimulation operations require large volumes of water. Our inability to locate sufficient amounts of water or dispose of or recycle water used in our drilling and production operations, could adversely impact our operations. Drought conditions, competing water uses, and other physical disruptions to our access to water could adversely affect our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic stimulation or disposal of waste, including but not limited to produced water, drilling fluids and other wastes associated with the development or production of natural gas.
The SDWA and the Underground Injection Control (the “UIC”) Program
The SDWA and the UIC program promulgated under the SDWA and relevant state laws regulate the drilling and operation of disposal wells that manage produced water (brine wastewater containing salt and other constituents produced by natural gas and oil wells). The EPA directly administers the UIC program in some states, and in others administration is delegated to the state. Permits must be obtained before developing and using deep injection wells for the disposal of produced water, and well casing integrity monitoring must be conducted periodically to ensure the well casing is not leaking produced water to groundwater. Contamination of groundwater by natural gas and oil drilling, production and related operations may result in fines, penalties, remediation costs and natural resource damages, among other sanctions and liabilities under the SDWA and other federal and state laws. In addition, third-party claims may be

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filed by landowners and other parties claiming damages for groundwater contamination, alternative water supplies, property impacts and bodily injury.
Solid and Hazardous Waste
Although oil and natural gas wastes generally are exempt from regulation as hazardous wastes under the federal RCRA and some comparable state statutes, it is possible some wastes we generate presently or in the future may be subject to regulation under the RCRA or other similar statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including hazardous wastes and there is no guarantee that the EPA or the states will not adopt more stringent requirements in the future. For example, in December 2016, the EPA and several environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as a hazardous waste under RCRA. In keeping with the consent decree, in April 2019, EPA signed a determination that revision of these regulations was not warranted at this time. However, a loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the costs to manage and dispose of generated wastes.
In addition, the federal CERCLA can impose joint and several liability without regard to fault or legality of conduct on classes of persons who are statutorily responsible for the release of a hazardous substance into the environment. These persons can include the current and former owners or operators of a site where a release occurs, and anyone who disposes or arranges for the disposal of a hazardous substance released at a site. Under CERCLA, such persons may be subject to strict, joint and several liability for the entire cost of cleaning up hazardous substances that have been released into the environment and for other costs, including response costs, alternative water supplies, damage to natural resources and for the costs of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Each state also has environmental cleanup laws analogous to CERCLA. Petroleum hydrocarbons or wastes may have been previously handled, disposed of, or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. These properties and any materials disposed or released on them may subject us to liability under CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, to contribute to remediation costs, or to perform remedial activities to prevent future environmental harm.
Endangered Species Act
The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their habitats. Some of our operations may be located in areas that are designated as habitats for endangered or threatened species. In February 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, the U.S. Fish and Wildlife Service continues its effort to make listing decisions and critical habitat designations where necessary for over 250 species, as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia. The U.S. Fish and Wildlife Service agreed to complete the review by the end of the agency’s 2017 fiscal year. The agency missed the deadline but continues to review species for listing under the ESA. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MTBA”). The federal government in the past has pursued enforcement actions against oil and natural gas companies under the Migratory Bird Treaty Act after dead migratory birds were found near reserve pits associated with drilling activities. However, in January 2020, the Department of Interior proposed new regulations clarifying that only the intentional taking of protected migratory birds is subject to prosecution under the MTBA. The ESA and MBTA have not previously had a significant impact on our operations. Nevertheless, the designation of previously unprotected species, such as the Greater Sage Grouse, as being endangered or threatened could cause us to incur additional costs or become subject to operating restrictions in areas where the species are known to exist. If a portion of any area where we operate were to be designated as a critical or suitable habitat, it could adversely impact the value of our assets.

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Air Emissions
The CAA and comparable state laws restrict the emission of air pollutants from many sources (e.g., compressor stations), through the imposition of air emission standards, construction and operating permitting programs and other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (the “NAAQS”) for ozone from 75 to 70 parts per billion and completed attainment/non-attainment designations in 2018. In 2016, EPA published a Federal Implementation Plan (“FIP”) to implement minor new source review for oil and gas production and processing on tribal lands. In April 2018, the EPA proposed revisions to reportedly streamline the FIP. Although neither the original FIP nor its revisions originally applied to areas of ozone non-attainment, a May 2019 rule extended the FIP to the Indian country portion of the Uinta Basin Ozone Nonattainment Area.
Implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Over the next several years we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. In addition, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compound and methane emissions from certain stimulated oil and natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Subsequently, the Trump Administration has made several attempts to modify CAA regulations related to methane emissions from oil and gas sources. These attempts are subject to ongoing litigation. Most recently, in August 2019, the EPA proposed amendments to the existing methane requirements that, among other things, could rescind methane-specific requirements applicable to upstream facilities but retain requirements for volatile organic compound emissions. Legal challenges to any final rule rescinding federal methane requirements are expected.
In addition, the regulations place new requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. In May 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase the costs of development, which costs could be significant.
NEPA
Oil and natural gas exploration and production activities on federal lands are subject to NEPA. NEPA requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases. In January 2020, the Council on Environmental Quality issued a proposed revisions to NEPA regulations that seek to conform the scope of direct, indirect, and cumulative impact analyses for proposed projects subject to NEPA with existing case law; however, the final form or impact of any such revisions is uncertain at this time.
Water Resources
The CWA and analogous state laws restrict the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined to include, among other things, certain wetlands. Under the CWA, permits must be obtained for the discharge of pollutants into waters of the United States.

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The CWA provides for administrative, civil and criminal penalties for unauthorized discharges, both routine and accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated with construction activities. Pursuant to these laws and regulations, we may be required to develop and implement spill prevention, control and countermeasure plans, (“SPCC plans”) in connection with on-site storage of significant quantities of oil. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The CWA also prohibits the discharge of fill materials to regulated waters including wetlands without a permit from the U.S. Army Corps of Engineers. The process for obtaining permits has the potential to delay our operations. SPCC plans and other federal requirements require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Also, in June 2016, the EPA finalized new wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works.
In August 2015, the EPA and U.S. Army Corps of Engineers issued a rule expanding the scope of the federal jurisdiction over wetlands and other types of waters (the “Clean Water Rule”). However, there have been attempts to modify the Clean Water Rule by the Trump Administration. On January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows the definition of jurisdictional water relative to the Clean Water Rule. However, legal challenges to the new rule are expected, and multiple challenges to the EPA’s prior rulemakings remain pending. We cannot predict the outcome of any of this litigation. To the extent any final rule expands the range of properties subject to the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining dredge and fill activity permits in wetland areas, which could materially impact our operations in the San Joaquin basin and other areas.
In recent years, water districts and the California state government have implemented regulations and policies that may restrict groundwater extraction and water usage and increase the cost of water. 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, steamflooding and well drilling, completion and stimulation. We use water supplied from various local and regional sources, particularly for power plants and to support operations like steam injection in certain fields.
Natural Gas Sales and Transportation
Section 1(b) of the Natural Gas Act (the “NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company, but the status of these lines has never been challenged before FERC. The distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change based on future determinations by FERC, the courts, or Congress, and application of existing FERC policies to individual factual circumstances. Accordingly, the classification and regulation of some of our natural gas gathering facilities may be subject to challenge before FERC or subject to change based on future determinations by FERC, the courts, or Congress. In the event our gathering facilities are reclassified to FERC-regulated transmission services, we may be required to charge lower rates and our revenues could thereby be reduced.
FERC requires certain participants in the natural gas market, including natural gas gatherers and marketers which engage in a minimum level of natural gas sales or purchases, to submit annual reports regarding those transactions to FERC. Should we fail to comply with this requirement or any other applicable FERC-administered statute, rule, regulation or order, it could be subject to substantial penalties and fines.
Federal Energy Regulations
The enactment of the Public Utility Regulatory Policies Act (“PURPA”) and the adoption of regulations thereunder by the FERC provided incentives for the development of cogeneration facilities such as those we own. A domestic

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electricity generating project must be a Qualifying Facility (“QF”) under FERC regulations in order to benefit from certain rate and regulatory incentives provided by PURPA.
PURPA provides two primary benefits to QFs. First, QFs and entities that own QFs generally are relieved of compliance with certain federal regulations pursuant to the Public Utility Holding Company Act of 2005. Second, FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility’s avoided cost and that the utility sell back-up power to the QF on a nondiscriminatory basis. The Energy Policy Act of 2005 amended PURPA to allow a utility to petition FERC to be relieved of its obligation to enter into any new contracts with QFs if FERC determines that a competitive wholesale electricity market is available to QFs in the service territory. Effective November 23, 2011, the California utility companies have been relieved of their PURPA obligation to enter into new contracts with cogeneration QFs larger than 20 MW. While the California utility companies are still required to enter into new contracts with smaller facilities, such as our Cogen 18 facility, there is no assurance that we will be able to secure new contracts upon the expiration of the existing contracts for our larger facilities. Even if new contracts are available for our larger facilities, there is no assurance that the prices and terms of such contracts will not adversely affect our financial condition, results of operations and net cash provided by operating activities.
State Energy Regulation
The CPUC has broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in California and to promulgate regulation for implementation of PURPA. Since a power sales agreement becomes a part of a utility’s cost structure (generally reflected in its retail rates), power sales agreements between electric utilities and independent electricity producers, such as us, are under the regulatory purview of the CPUC. While we are not subject to direct regulation by the CPUC, the CPUC’s implementation of PURPA and its authority granted to the investor-owned utilities to enter into other PPAs are important to us, as is other regulatory oversight provided by the CPUC to the electricity market in California. The CPUC’s implementation of PURPA may be subject to change based on past and future determinations by the courts, or policy determinations made by the CPUC.
Operations on Indian Lands
A portion of our leases and drill-to-earn arrangements in the Uinta basin operating area and some of our future leases in this and other operating areas may be subject to laws promulgated by an Indian tribe with jurisdiction over such lands. In addition to potential regulation by federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations may apply to lessees, operators and other parties on Indian lands, tribal or allotted. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, tribal employment and contractor preferences and numerous other matters. Further, lessees and operators on Indian lands may be subject to the jurisdiction of tribal courts, unless there is a specific waiver of sovereign immunity by the relevant tribe allowing resolution of disputes between the tribe and those lessees or operators to occur in federal or state court.
These laws, regulations and other issues present unique risks that may impose additional requirements on our operations, cause delays in obtaining necessary approvals or permits, or result in losses or cancellations of our oil and natural gas leases, which in turn may materially and adversely affect our operations on Indian lands.
Pipeline Safety Regulations
The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, the courts or Congress may make determinations that affect PHMSA’s regulations or their applicability to our pipelines. These determinations may affect the costs we incur in complying with applicable safety regulations.

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Worker Safety
The Occupational Safety and Health Act of 1970 (“OSHA”) and analogous state laws regulate the protection of the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. In December 2015, the U.S. Departments of Justice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties.
Future Impacts and Current Expenditures
We cannot predict how future environmental laws and regulations may impact our properties or operations. For the year ended December 31, 2019, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2020 or that will otherwise have a material impact on our financial position, results of operations or cash flows.
Employees
As of December 31, 2019, we had 355 employees. None of our employees are currently covered under collective bargaining/union agreements.
We consider employee relations to be good. We strive to create a corporate culture that is reflective of our core values, including accountability, ownership, communication, leadership and entrepreneurship. We are committed to the development of our employees and provide learning and engagement opportunities.
Corporate Information
On May 11, 2016, our predecessor filed petitions for reorganization in the U.S. Bankruptcy Court (the “Bankruptcy Court”) for the Southern District of Texas (collectively, the “Chapter 11 Proceedings”). On February 28, 2017, Berry LLC emerged from bankruptcy as a stand-alone company and wholly-owned subsidiary of Berry Corp. with new management, a new board of directors and new ownership. Berry Corp. was incorporated in Delaware in February 2017 in connection with the Chapter 11 Proceedings. A final decree closing the Chapter 11 Proceedings was entered September 28, 2018, with the Court retaining jurisdiction as described in the confirmation order and without prejudice to the request of any party-in-interest to reopen the case including with respect to certain, immaterial remaining matters. Berry Corp. completed its IPO and its common stock has been trading on the Nasdaq Global Select Market ("NASDAQ") under the ticker symbol "BRY" since July 26, 2018.
We have executive offices located at 11117 River Run Boulevard, Bakersfield, California 93311 and at 16000 N. Dallas Pkwy, Ste. 500, Dallas, Texas 75248, where we have our principal executive offices. Our telephone number is (661) 616-3900 and our web address is www.bry.com. Information contained in or accessible through our website is not, and should not be deemed to be, part of this report.
Item 1A. Risk Factors
If any of the following risks actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only risks and uncertainties we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may ultimately materially affect our business.

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Risks Related to Our Business and Industry
The risks and uncertainties described below are among the items we have identified that could materially adversely affect our business, production, strategy, growth plans, acquisitions, hedging, reserves quantities or value, operating or capital costs, financial condition, results of operations, liquidity, cash flows, our ability to meet our capital expenditure plans and other obligations and financial commitments, and our plans to return capital.
Oil, natural gas and NGL prices are volatile and directly affect our results.
The prices we receive for our oil, natural gas and NGL production and pay for natural gas purchases heavily influence our revenue, operating expenses, profitability, access to capital, future rate of growth and the carrying value of our properties. Prices for these commodities have, and may continue to, fluctuate widely in response to market uncertainty and to relatively minor changes in the supply of and demand for oil, natural gas and NGLs. For example, Brent crude oil contract prices ranged from $54.91 per Bbl at the beginning of 2019, to a high of $74.57 per Bbl and back to $56.23 per Bbl at the end of 2019. In California, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, as well as the SoCal Index which were as low as $0.99 per MMBtu and as high as $22.38 per MMBtu for a short time in 2019 due to market disruptions. Prices remain volatile in 2020. The prices we receive for our production and pay for our gas purchases, and the levels of our production, depend on numerous factors beyond our control, which include the following:
worldwide and regional political, regulatory, economic and social conditions impacting the global supply and demand for, and transportation costs of, oil and natural gas, including relaxation of rules against U.S. exports;
military action, war, sanctions and other conflicts;
the price and quantity of foreign imports of oil, particularly in California which imports from foreign countries more than half of the oil it consumes;
the impact of the U.S. dollar exchange rates on oil and expectations about future oil and gas prices;
prevailing prices on local price indexes in the areas in which we operate which are affected by local market conditions and the proximity, capacity, cost and availability of gathering and transportation facilities as well as refining and processing disruptions or bottlenecks;
the level of global exploration, development and production, and resulting inventories, including the significant increase in U.S. activities over the past decade;
actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
actions of other significant producers;
the cost of exploring for, developing, producing and transporting reserves;
weather conditions and natural disasters;
other irregular events that impact our ability to conduct business or demand for our products, such as the coronavirus outbreak; and
technological advances, conservation efforts and availability of alternative fuels affecting oil and gas consumption.    
Lower oil prices and higher gas prices may reduce our cash flow, borrowing ability and access to capital needed to develop existing and future reserves.
Lower oil prices and higher gas prices generally reduce the quantity of our oil reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. Lower gas prices may also reduce our gas reserves. In addition, a portion of our PUDs may no longer meet the economic producibility criteria

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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, oil and natural gas prices affect our drilling economics, and lower oil prices may require us to postpone or eliminate all or part of our development program, and result in the reduction of some of our proved undeveloped reserves, reducing the net present value of our proved reserves.
Our business requires continual capital expenditures. We may be unable to fund these investments through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or production. Our capital program is also susceptible to risks, including regulatory and permitting risks, that could materially affect its implementation.
Our industry is capital intensive. We have a 2020 capital expenditure budget of approximately $125 to $145 million. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of permits, and our ability to obtain them in a timely manner or at all, legal and regulatory processes and other restrictions, and technological and competitive developments. A reduction or sustained decline in commodity prices from current levels may force us to reduce our capital expenditures, which would negatively impact our ability to grow production. Current and future laws and regulations may prevent us from being able to execute our drilling programs and development and optimization projects.
We expect to fund our capital expenditures with cash flows from our operations; however, our cash flows from operations, and access to capital should such cash flows prove inadequate, are subject to a number of variables, including:
the volume of hydrocarbons we are able to produce from existing wells;
the prices at which our production is sold and our operating expenses;
the success of our hedging program;
our proved reserves, including our ability to acquire, locate and produce new reserves;
our ability to borrow under the RBL Facility;
and our ability to access the capital markets.
If our revenues or the borrowing base under the RBL Facility decrease as a result of lower oil, natural gas and NGL prices, lack of required permits and other operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital were needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. Any additional debt financing, would carry interest costs, diverting capital from our business activities, which in turn could lead to a decline in our reserves and production. If cash flows generated by our operations or available borrowings under the RBL Facility were not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change the requirements governing our operations, including the permitting approval process for oil and gas exploration, extraction, operations and production activities, well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy and plans.
Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to environmental protection and 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 in these areas. For example, the jurisdiction, duties and enforcement authority of various state agencies have

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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 of certain oil and natural gas activities in 2020. 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.
See “Items 1 and 2. Business and Properties—Regulation of Health, Safety and Environmental Matters” for a description of laws and regulations that affect our business. To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, fluid injection and disposal, stimulation, operation, maintenance, transportation, marketing, site remediation, decommissioning, abandonment and water recycling and reuse. These permits are generally subject to protest, appeal or litigation, which could in certain cases delay or halt projects, production of wells and other operations. Additionally, failure to comply may result in the assessment of administrative, civil and criminal fines and penalties and liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting our operations.
Our operations in California are subject to numerous and stringent state, local and other laws and regulations that could delay or otherwise adversely impact our operations. For example, in 2019, new legislation expanded CalGEM’s duties 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 controlling emissions from idle and abandoned wells, evaluate plugging and abandonment and restoration costs and associated bonding requirements. Additionally, 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 WST permits and PALs for underground injection 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 January 2020, CalGEM issued a formal notice to operators, including us, that they had issued restrictions imposing a moratorium to prohibit new underground oil-extraction wells from using high-pressure cyclic steaming process. Most recently, on February 24, 2020, a California Court of Appeals effectively invalidated a Kern County ordinance that streamlined the permitting process for oil and gas exploration, extraction, operations and production activities in unincorporated Kern County, until the County makes certain revisions to the Kern County EIR supporting the ordinance and recertifies it. Other state agencies, including CalGEM, have relied on the Kern County EIR to satisfy the CEQA requirements in connection with permitting and project approval decisions for oil and gas projects in unincorporated Kern County. We cannot predict how long it will take Kern County to recertify the Kern County EIR or to conduct a new EIR, either of which could ultimately result in the imposition of more onerous permit application requirements and limits on exploration and production activities. It is not yet known how Kern County will resolve this issue, or how long it will take to do so, and we cannot predict how long it will take or what the requirements and costs will be to obtain new permits and project approvals in the interim. It is also not yet known whether there will be significant delays or a pause in the issuance of new permits and approvals in unincorporated Kern County pending resolution of this issue.
With these regulatory changes in 2019, we have experienced delays in obtaining the permits required to develop our properties in accordance with our existing development and production plans. In late 2019 and in early 2020, we discontinued two drilling rigs and we are currently operating one rig. We are actively reviewing the UIC developments and considering the potential impacts of the Kern County Ruling, as well as our internal internal processes. As part of a contingency plan, we are preparing our internal resources to support a more time-intensive and burdensome permitting application process and the potential environmental impact review requirements to mitigate the impact to our development and production plans. If we are unable to obtain the required permits on a timely basis or at all, we may not be able to continue operating this one rig or to redeploy the other two as planned. If we are unable to employ these rigs on a timely basis, or at all, or execute our drilling program, our financial and operating results could be adversely affected.

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Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. Permanent restrictions imposed to protect threatened or endangered species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.
Our customers, including refineries and utilities, and the businesses that transport our products to customers are also highly regulated. For example, federal and state agencies have subjected or, proposed subjecting, more gas and liquid gathering lines, pipelines and storage facilities to regulations that have increased business costs and otherwise affect the demand, volatility and other aspects of the price we pay for fuel gas. Certain municipalities have enacted restrictions on the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect the retail natural gas market for our utility customers and the demand and prices we receive for the natural gas we produce.
Costs of compliance may increase, and operational delays or restrictions may occur as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations, each of which has occurred in the past. For example, our costs have recently begun to increase due to new fluid injection regulations, data requirements for permitting, and idle well decommissioning regulations. For instance, in 2019 we paid $27 million in asset retirement obligations, an increase from $8 million in 2018, largely due to the new idle well regulations and our focus on EH&S as we develop existing fields. In addition, we may experience delays, as we have in the past, due to insufficient internal processes and personnel resource constraints at regulatory agencies that impede their ability to process permits in a timely manner that aligns with our production projects.
Government authorities and other organizations continue to study health, safety and environmental aspects of oil and natural gas operations, including those related to air, soil and water quality, ground movement or seismicity and natural resources. Government authorities have also adopted or proposed new or more stringent requirements for permitting, well construction and public disclosure or environmental review of, or restrictions on, oil and natural gas operations. 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, and preclude us from drilling, completing or stimulating wells, 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 California governor or legislature may take with respect to the regulation of our business, the oil and natural gas industry or the state's economic, fiscal or environmental policies.
We may be unable to, or may choose not to, enter into sufficient fixed-price purchase or other hedging agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam operations economically or at desired levels, and our commodity-price risk-management activities may prevent us from fully benefiting from price increases and may expose us to other risks.
To develop our heavy oil in California we must economically generate steam using natural gas. We seek to reduce our exposure to the potential unavailability of, pricing increases for, and volatility in pricing of, natural gas by entering into fixed-price purchase agreements and other hedging transactions. We seek to reduce our exposure to potential price increases and volatility in pricing of oil by entering into swaps, calls and other hedging transactions. We may be unable to, or may choose not to, enter into sufficient such agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam operations economically or at desired levels. Our commodity-price risk-management activities may prevent us from fully benefiting from price increases. Additionally, our hedges are based on major oil and gas indexes, which may not fully reflect the prices we realize locally. Consequently, the price protection we receive may not fully offset local price declines.

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As of December 31, 2019, we have hedged crude oil production at the following approximate volumes and Brent prices: 16.7 MBbl/d at $64 per barrel in 2020, and 1.0 MBbl/d at $59 per barrel in 2021. We have also hedged gas purchases at the following approximate volumes and prices: 51.7 MMbtu/d at $2.95 per in 2020, and 1.2 MMbtu/d at $2.50 in 2021.
Our commodity-price risk-management activities may also expose us to the risk of financial loss in certain circumstances, including instances in which:
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.
Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.
Estimation of reserves and related future net cash flows is a partially subjective process of estimating accumulations of oil and natural gas that includes many uncertainties. Our estimates are based on various assumptions, which may ultimately prove to be inaccurate, including:
the similarity of reservoir performance in other areas to expected performance from our assets;
the quality, quantity and interpretation of available relevant data;
commodity prices (see “—Oil, natural gas and NGL prices are volatile and directly affect our results.”);
production, operating costs, taxes and costs related to GHG regulations;
development costs;
the effects of government regulations; and 
future workover and asset retirement costs.
Misunderstanding these variables, inaccurate assumptions, changed circumstances or new information could require us to make significant negative reserves revisions.
We currently expect improved recovery, extensions and discoveries and, potentially acquisitions, to be our main sources for reserves additions. However, factors such as the availability of capital, geology, government regulations and permits, the effectiveness of development plans and other factors could affect the source or quantity of future reserves additions. Any material inaccuracies in our reserves estimates could materially affect the net present value of our reserves, which could adversely affect our borrowing base and liquidity under the RBL Facility, as well as our results of operations.
Unless we replace oil and natural gas reserves, our future reserves and production will decline.
Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Success requires us to deploy sufficient capital to projects that are geologically and economically attractive which is subject to the capital, development, operating and regulatory risks already discussed above under the heading “—Our business requires continual capital expenditures. We may be unable to fund these investments through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or production. Our capital program is also susceptible to risks, including regulatory and permitting risks, that could materially affect its implementation.” 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.

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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business.
The success of our development, production and acquisition activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable production or may result in a downward revision of our estimated proved reserves due to:
poor production response;
ineffective application of recovery techniques;
increased costs of drilling, completing, stimulating, equipping, operating, maintaining and abandoning wells;
delays or cost overruns caused by equipment failures, accidents, environmental hazards, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes and other matters; and
misinterpretation of geophysical and geological analyses, production data and engineering studies.
Additional factors may delay or cancel our operations, including:
delays due to regulatory requirements and procedures, including unavailability or other restrictions limiting permits and limitations on water disposal, emission of GHGs, steam injection and well stimulation, such as California’s recent limitations on cyclic steaming above the fracture gradient;
pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment, qualified personnel or supplies including water for steam used in production or pressure maintenance;
delays in access to production or pipeline transmission facilities; and
power outages imposed by utilities which provide a portion of our electricity needs in order to avoid fire hazards and inspect lines in connection with seasonal strong winds, have begun to occur recently and may impact our operations.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to property, reserves and equipment, pollution, environmental contamination and regulatory penalties.
We may not drill our identified sites at the times we scheduled or at all.
We have specifically identified locations for drilling over the next several years, which represent a significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. Legislative and regulatory developments, such as the California moratorium on approval of new high-pressure cyclic steam wells pending a study of the practice to address surface expressions experienced by certain operators, could prevent us from planned drilling activities. Additionally, as we experienced late in the fourth quarter and continuing to date, new regulations and legislative activity could result in a significant decline in the permits required to develop our properties in accordance with our plans. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. Accordingly, we cannot guarantee that these prospective drilling locations or any other drilling locations we have identified will ever be drilled or if we will be able to economically produce oil or natural gas from these drilling locations. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring in the next three years represented approximately 13% of our total net acreage at December 31, 2019.

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Potential future legislation may generally affect the taxation of natural gas and oil exploration and development companies and may adversely affect our operations.
In past years, federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to natural gas and oil exploration and development companies.
For example, in California, there have been proposals for new taxes on profits that might have a negative impact on us. Although the proposals have not become law, campaigns by various special interest groups could lead to future additional oil and natural gas severance or other taxes. The imposition of such taxes could significantly reduce our profit margins and cash flow and otherwise significantly increase our costs.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.
Our future success will depend on our ability to evaluate, select and acquire suitable properties, market our production and secure skilled personnel to operate our assets in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ greater financial, technical and personnel resources than we do.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets or enter into attractive joint ventures, and any inability to do so may disrupt our business and hinder our ability to grow.
There is no guarantee we will be able to identify or complete attractive acquisitions. Our capital expenditure budget for 2020 does not allocate any amounts for acquisitions of oil and natural gas properties. If we make acquisitions, we would need to use cash flows or seek additional capital, both of which are subject to uncertainties discussed in this section. Competition may also increase the cost of, or cause us to refrain from, completing acquisitions. Our debt arrangements impose certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness. See “—Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.” In addition, the success of completed acquisitions will depend on our ability to integrate effectively the acquired business into our existing operations, may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.
We are dependent on our cogeneration facilities to produce steam for our operations. Contracts for the sale of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our operations.
We are dependent on five cogeneration facilities that, combined, provide approximately 22% of our steam capacity and approximately 48% of our field electricity needs in California at a discount to market rates. To further offset our costs, we sell surplus power to California utility companies produced by three of our cogeneration facilities under long-term contracts. Should we lose, be unable to renew on favorable terms, or be unable to replace such contracts, we may be unable to realize the cost offset currently received. Our ability to benefit from these facilities is also affected by our ability to consistently generate surplus electricity and fluctuations in commodity prices. For example, during 2019 electricity sales decreased by $6 million, or 17%, due to lower unit sales resulting from unexpected downtime at our largest cogen during the summer when we receive peak pricing, and lower year–over–year gas pricing. Furthermore, market fluctuations in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration facilities and any corresponding increase in the price of steam could significantly impact our operating costs. If we were unable to find new or replacement steam sources, lose existing sources or experience installation delays, we may be unable to maximize production from our heavy oil assets. If we were to lose our electricity sources, we would be subject to the electricity rates we could negotiate. For a more detailed discussion of our electricity sales contracts, see “Items 1 and 2. Business and Properties—Operational Overview—Electricity.”

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Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities. In addition, the borrowing base under the RBL Facility is subject to periodic redeterminations and our lenders could reduce capital available to us for investment.
The RBL Facility and the indenture governing our 2026 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. Failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. The amount available to be borrowed under the RBL Facility is subject to a borrowing base, which will be redetermined semiannually and will depend on the estimated volumes and cash flows of our proved oil and natural gas reserves and other information deemed relevant by the administrative agent of, or two-thirds of the lenders under, the RBL facility. Reduction of our borrowing base under the RBL Facility could reduce the capital available to us for investment in our business. For details regarding the terms of the RBL Facility and our 2026 Notes, see "Liquidity and Capital Resources".
These agreements contain covenants, that, among other things, limit our ability to:
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
transfer, sell or dispose of assets;
make investments;
create certain liens securing indebtedness;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
hedge future production or interest rates;
repay or prepay certain indebtedness prior to the due date;
engage in transactions with affiliates; and
engage in certain other transactions without the prior consent of the lenders.
In addition, the RBL Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios, which may limit our ability to borrow funds to withstand a future downturn in our business, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of these limitations.
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
The amount available to be borrowed under the RBL Facility is subject to a borrowing base and will be redetermined semiannually and will depend on the estimated volumes and cash flows of our proved oil and natural gas reserves and other information deemed relevant by the administrative agent of, or two-thirds of the lenders under, the RBL Facility. We, the administrative agent and lenders, each may request one additional redetermination between each regularly scheduled redetermination. Furthermore, our borrowing base is subject to automatic reductions due to certain asset sales and hedge terminations, the incurrence of certain other debt and other events as provided in the RBL Facility. For example, the RBL Facility currently provides that to the extent we incur certain unsecured indebtedness, our borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt that exceeds the amount, if any, of certain other debt that is being refinanced by such unsecured debt. We could be required to repay a portion of the RBL Facility to the extent that after a redetermination our outstanding borrowings at such time exceed the redetermined

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borrowing base. Currently, we have elected to limit the amount we can borrow under the RBL Facility to an amount well below our borrowing base.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
Our ability to make scheduled payments on or to refinance our debt obligations, including the RBL Facility and our 2026 Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors that may be beyond our control. If oil and natural gas prices were to deteriorate and remain at low levels for an extended period of time, our cash flows from operating activities may be insufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The RBL Facility and our 2026 Notes currently restrict our ability to dispose of assets and our use of the proceeds from any such disposition. We may not be able to consummate dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.
Declines in commodity prices, changes in expected capital development, increases in operating costs or adverse changes in well performance may result in write-downs of the carrying amounts of our assets.
We evaluate the impairment of our oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. For example, for the year ended December 31, 2019, we recorded an impairment charge of $51 million for the Piceance gas properties in Colorado.
We have significant concentrations of credit risk with our customers and the inability of one or more of our customers to meet their obligations or the loss of any one of our major oil and natural gas purchasers may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We have significant concentrations of credit risk with the purchasers of our oil and natural gas. For the year ended December 31, 2019, sales to Andeavor, Phillips 66 and Kern Oil & Refining accounted for approximately 36%, 24% and 13%, respectively, of our sales. This concentration may impact our overall credit risk because our customers may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. If the purchasers of our oil and natural gas become insolvent, we may be unable to collect amounts owed to us. Also, if we were to lose any one of our major customers, the loss could cause us to cease or delay both production and sale of our oil and natural gas in the area supplying that customer.
Due to the terms of supply agreements with our customers, we may not know that a customer is unable to make payment to us until almost two months after production has been delivered. We do not require our customers to post collateral to protect our ability to be paid.
Our producing properties are located primarily in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.
We operate primarily in California. This geographic concentration disproportionately affects the success and profitability of our operations exposing us to local price fluctuations, changes in state or regional laws and regulations, political risks, limited acquisition opportunities where we have the most operating experience and infrastructure, limited storage options, drought conditions, and other regional supply and demand factors, including gathering, pipeline and transportation capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. We discuss such specific risks in more detail elsewhere in this section.

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Many of our operations are currently conducted in locations in California that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.
We currently conduct operations in California near known wildfire and mudslide areas and earthquake fault zones. A future natural disaster, such as a fire, mudslide or an earthquake, could cause substantial delays in our operations, damage or destroy equipment, prevent or delay transport of our products and cause us to incur additional expenses, which would adversely affect our business, financial condition and results of operations. In addition, our facilities would be difficult to replace and would require substantial lead time to repair or replace. These events could occur with greater frequency as a result of the potential impacts from climate change. The insurance we maintain against earthquakes, mudslides, fires and other natural disasters would not be adequate to cover a total loss of our facilities, may not be adequate to cover our losses in any particular case and may not continue to be available to us on acceptable terms, or at all.
Operational issues and inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise could restrict access to markets for the commodities we produce.
Our ability to market our production of oil, gas and NGLs depends on a number of factors, including the proximity of production fields to pipelines, refineries and terminal facilities, competition for capacity on such facilities, damage, shutdowns and turnarounds at such facilities and their ability to gather, transport or process our production. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely, and expect to rely in the future, on third party facilities for services such as storage, processing and transmission of our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. If our access to markets for commodities we produce is restricted, our costs could increase and our expected production growth may be impaired.
Derivatives legislation and regulations could have an adverse effect on our ability to use derivative instruments to reduce the risks associated with our business.
The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the over-the-counter (“OTC”) derivatives market and entities, like us, that participate in that market. Rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may hold and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to, or otherwise be affected by, such regulations. Even though certain of the European Union implementing regulations have become effective, the ultimate effect on our business of the European Union implementing regulations (including future implementing rules and regulations) remains uncertain.
Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for the oil and natural gas we produce.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our oil and natural gas exploration and production operations are subject to a series of regulatory,

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political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, California, through the CARB has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado.
In September 2018, California adopted a law committing California , the fifth largest economy in the world, to the use of 100% zero-carbon electricity by 2045, and the Governor of California also signed an executive order committing California to total economy-wide carbon neutrality by 2045. We cannot predict how these various laws, regulations and orders may ultimately affect our operations. However, these initiatives could result in decreased demand for the oil, natural gas, and NGLs that we produce, and therefore adversely effect our revenues and results of operations.
At the international level, there is a non-binding agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. Although the United States has announced its withdrawal from such agreement, effective November 4, 2020, several U.S. states and local governments have announced their intention to adhere to the goals of the Paris Agreement.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates seeking the office of the President of the United States in 2020. Two critical declarations made by one or more candidates running for the Democratic nomination for President include threats to take actions banning hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties. Our operations involve the use of hydraulic fracturing activities and we also have operations on federal lands under the jurisdiction of the BLM. Other actions that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as the reversal of the United States’ withdrawal from the Paris Agreement in November 2020.
Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but withheld material information from their investors by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide

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funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years by environmental activists, proponents of the international Paris Agreement, and other groups concerned about climate change to restrict fossil fuel producers’ access to capital. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers such as ourselves or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. Moreover, there are increasing risks to operations resulting from the potential physical impacts of climate change, such as drought, wildfires, damage to infrastructure and resources from flooding and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not fully insured against all risks. Our oil and natural gas exploration and production activities, are subject to risks such as fires, explosions, oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment, equipment failures and industrial accidents. We are exposed to similar risks indirectly through our customers and other market participants such as refiners. Other catastrophic events such as earthquakes, floods, mudslides, fires, droughts, contagious diseases, terrorist attacks and other events that cause operations to cease or be curtailed may adversely affect our business and the communities in which we operate. For example, utilities have begun to suspend electric services to avoid wildfires during windy periods in California, a risk that is not insured. We may be unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented.
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of the attention of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change materially from one period to the next.
The loss of senior management or technical personnel could adversely affect operations.
We depend on, and could be deprived of, the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of services of any of these individuals.
Information technology failures and cyberattacks could affect us significantly.
We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. Without accurate data from and access to these systems and networks, our ability to communicate and control and manage our business could be adversely affected.

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We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Risks Related to our Capital Stock
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
A large portion of our common stock is beneficially owned by a relatively small number of stockholders. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures, hostile takeovers or other transactions, including the payment of dividends or the issuance of additional equity or debt, that, in their judgment, could enhance their investment in us or in another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations.
Our significant stockholders and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in the Certificate of Incorporation could enable our significant stockholders to benefit from corporate opportunities that might otherwise be available to us.
Our governing documents provide that our stockholders and their affiliates are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, the Certificate of Incorporation, among other things:
permits stockholders to make investments in competing businesses; and
provides that if one of our directors who is also an employee, officer or director of a stockholder (a “Dual Role Person”), becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.
Our director who is a Dual Role Person may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which our stockholders have invested, in which case we may not become aware of, or otherwise have the ability to pursue, such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to be unavailable to us or causing them to be more expensive for us to pursue.
Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Certain of our largest stockholders comprised creditors of Berry LLC prior to the Chapter 11 Proceedings and we cannot predict when or whether they will sell their shares of common stock. Future sales, or concerns about them, may put downward pressure on the market price of our common stock
We may sell or otherwise issue additional shares of common stock or securities convertible into shares of our common stock. Berry Corp.'s Certificate of Incorporation provides for authorized capital stock consisting of 750,000,000

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shares of common stock and 250,000,000 shares of preferred stock. In addition, we registered shares of the great majority of our common stock for resale. For more information see Exhibit 4.4 to our Annual Report on Form 10-K.
The issuance of any securities for acquisitions, financing, upon conversion or exercise of convertible securities, or otherwise may result in a reduction of the book value and market price of our outstanding common stock. If we issue any such additional securities, the issuance will cause a reduction in the proportionate ownership and voting power of all current stockholders. We cannot predict the size of any future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
Shares of our common stock are also reserved for issuance as equity-based awards to employees, directors and certain other persons under the second amended and restated 2017 Omnibus Incentive Plan (our “Omnibus Plan”). We have filed a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our Omnibus Plan. Subject to the satisfaction of vesting conditions, the expiration of certain lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction. Investors may experience dilution in the value of their investment upon the exercise of any equity awards that may be granted or issued pursuant to the Omnibus Plan in the future.
The payment of dividends will be at the discretion of our Board of Directors.
While we have regularly declared a quarterly dividend since our July IPO, including a dividend of $0.12 per share for the first quarter of 2020, and we currently intend to continue to pay a dividend , the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deems relevant. Covenants contained in our RBL Facility and the indentures governing our 2026 Notes could limit the payment of dividends. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
The Certificate of Incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.
We are an “emerging growth company,” and are able take advantage of reduced disclosure requirements applicable to “emerging growth companies,” which could make our common stock less attractive to investors.
We are an “emerging growth company” and, for as long as we continue to be an “emerging growth company,” we intend to take advantage of certain exemptions from various reporting requirements, including auditor attestation requirements or any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding a non-binding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We could be an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the first fiscal year in which our annual gross revenues exceed $1.07 billion, (ii) as of the end of the fiscal year that we become a

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“large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common stock that is held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or (iii) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.
We intend to take advantage of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards which lasts until those standards apply to private companies or we no longer qualify as an emerging growth company. Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those companies who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable.
To the extent investors find our common stock less attractive as a result of our reduced reporting and exemptions, there may be a less active trading market for our common stock, and our stock price may be more volatile.
Our internal control over financial reporting is not currently required to meet all of the standards required by Section 404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and share price.
Section 404 of the Sarbanes-Oxley Act requires us to provide annual management assessments of the effectiveness of our internal control over financial reporting. However, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act until we are no longer an “emerging growth company,” which could be up to five years from our IPO.
Effective internal controls are necessary for us to provide reliable financial reports, safeguard our assets, and prevent fraud. If we cannot provide reliable financial reports, safeguard our assets or prevent fraud, our reputation and operating results could be harmed. The rules governing the standards that must be met for our management to assess our internal control over financial reporting are complex and require significant documentation, testing and possible remediation.
We may encounter problems or delays in completing the implementation of effective internal controls. Further, failure to achieve and maintain an effective internal control environment could have a material adverse effect on our business and share price and could limit our ability to report our financial results accurately and timely.
Certain provisions of our Certificate of Incorporation and Bylaws, may make it difficult for stockholders to change the composition of our board of directors and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of the Certificate of Incorporation and Bylaws may have the effect of delaying or preventing changes in control if our board of directors determines that such changes in control are not in the best interests of us and our stockholders. For more information see Exhibit 4.4 to our Annual Report on Form 10-K.
For example, the Certificate of Incorporation and Bylaws include provisions that (i) authorize our board of directors to issue “blank check” preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval and (ii) establish advance notice procedures for nominating directors or presenting matters at stockholder meetings.
These provisions could enable the board of directors to delay or prevent a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors, which is responsible for appointing the members of our management.

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Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders, (iii) any action asserting a claim against us, our directors, officers or employees arising pursuant to any provision of the Delaware General Corporation Law, our Certificate of Incorporation or our Bylaws or (iv) any action asserting a claim against us, our directors, officers or employees that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having subject matter jurisdiction and personal jurisdiction over the indispensable parties named as defendants therein. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.
Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under the RBL Facility may bear interest rates in relation to LIBOR, depending on our selection of repayment options. On July 27, 2017, the Financial Conduct Authority in the U.K. announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR ceases to exist, we may need to renegotiate the RBL Facility and may not be able to do so with terms that are favorable to us. The overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
For additional information regarding legal proceedings, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Commitments, and Contingencies” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations.”
Item 4. Mine Safety Disclosure
Not applicable.

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Part II
Item 5.    Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock has been trading on the Nasdaq Global Select Market ("NASDAQ") under the ticker symbol “BRY” since July 26, 2018. Prior to that there was no established public trading market for our common stock.
Holders of Record  
Our common stock was held by 33 stockholders of record at January 31, 2020.
Dividend Policy
We plan to use our operating cash flows to cover our interest requirements, fund operations at sustained production levels, and consistently return meaningful capital to stockholders through quarterly dividends. We expect remaining cash flows will be allocated to fund internal growth opportunities. Our dividends will be determined by our board of directors in light of existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors.
Securities Authorized for Issuance Under Equity Compensation Plans
On June 27, 2018, our Board approved our second amended and restated 2017 Omnibus Incentive Plan (the “Omnibus Plan”). A description of the plans can be found in Item 8. Financial Statements and Supplementary Data – Note 6–Equity. The aggregate number of shares of our common stock authorized for issuance under stock-based compensation plans for our employees and non-employee directors is 10 million, of which 3.0 million have been issued or reserved through December 31, 2019.
The following table summarizes information related to our equity compensation plans under which our equity securities are authorized for issuance as of December 31, 2019.
Plan Category

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

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

Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (#)(3)
Equity compensation plans not approved by security holders(2)

2,348,334

N/A

6,954,454
________________
(1)
The number of securities to be issued upon vesting of unvested restricted stock units ("RSUs") subject to time vesting and performance-based restricted stock units ("PSUs"), assumes maximum achievement of certain market-based performance goals over a specified period of time 
(2)
In connection with the IPO, our Board amended and restated the Company’s First Amended and Restated 2017 Omnibus Incentive Plan, which had amended and restated the Company’s 2017 Omnibus Incentive Plan (the “Prior Plans” and, collectively with the Omnibus Plan, the “Equity Compensation Plans”), which allowed us to grant equity-based compensation awards with respect to up to 10,000,000 shares of common stock (which number includes the number of shares of common stock previously issued pursuant to an award (or made subject to an award that has not expired or been terminated) under the Prior Plans), to employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Omnibus Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents and other types of awards.   
(3)
The number of securities remaining available for future issuances has been reduced by the number of securities to be issued upon settlement of RSUs subject to time vesting and PSUs assuming maximum achievement of certain market-based performance goals over a specified period of time   


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Sales of Unregistered Securities
In February 2019, we issued and sold 350,000 shares of our common stock to Berry LLC at par value for aggregate consideration of $350, and Berry LLC agreed to issue those shares on our behalf in satisfaction of any liability arising from the remaining unsecured claim pending related to the Chapter 11 Proceeding. The shares were issued pursuant to an exemption from registration under Section 1145(a) of the U.S. Bankruptcy Code.
Stock Repurchase Program
In December 2018, we announced that our Board of Directors had adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock they authorized repurchases of up to $50 million under the program at that time. Purchases may be made from time to time in the open market, in privately negotiated transactions or otherwise. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. As of December 31, 2019, we had purchased shares for the full $50 million initially authorized. In February 2020, the Board of Directors authorized the remaining $50 million of our $100 million repurchase program.
Our share repurchase activities for the three months ended December 31, 2019, were as follows:
Period
 
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
October 1 - 31, 2019
 

 
$

 

 
 
November 1 - 30, 2019
 
1,252,696

 
$
7.60

 
1,252,696

 
 
December 1 - 31, 2019
 
156,163

 
$
7.98

 
156,163

 
 
Total
 
1,408,859

 
$
7.64

 
1,408,859

 
$


In 2019, the Company repurchased 4,609,021 shares at an average price of $9.99. Since 2018, the Company has repurchased a total of 5,057,682 shares at an average price of $9.88 per share under the Stock Repurchase Program.
Performance Graph
The following graph compares the cumulative total return to stockholders on our common stock relative to the cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S. Exploration and Production indexes and the Vanguard Energy ETF (with reinvestment of all dividends). The graph assumes that on July 26, 2018, the date our common stock began trading on the NASDAQ, $100 was invested in our common stock and in each index, and that all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future performance.

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COMPARISON OF CUMULATIVE TOTAL RETURN(1)(2) 
Among Berry Corporation (bry), the S&P Smallcap 600 Index,
the Dow Jones U.S. Exploration & Production Index
and the Vanguard Energy ETF
https://cdn.kscope.io/b9e371a45229b0e93102db918d1b0dfb-chart-2ae00bf8b4765006a02.jpg
 
7/26/18
 
09/18
 
12/18
 
03/19
 
06/19
 
09/19
 
12/19
Berry Corporation (bry)
$
100.00

 
$
133.73

 
$
67.17

 
$
89.50

 
$
83.16

 
$
74.34

 
$
75.90

S&P Smallcap 600
$
100.00

 
$
104.71

 
$
83.66

 
$
93.37

 
$
95.12

 
$
94.93

 
$
102.72

Dow Jones U.S. Exploration & Production
$
100.00

 
$
102.81

 
$
71.18

 
$
80.30

 
$
78.12

 
$
72.14

 
$
79.29

Vanguard Energy ETF
$
100.00

 
$
99.64

 
$
73.67

 
$
86.02

 
$
82.49

 
$
76.35

 
$
80.50

__________
(1)
The performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended (the "Securities Act") or the Exchange Act except to the extent that we specifically request it be treated as soliciting material or specifically incorporate it by reference.
(2)
$100 invested on July 26, 2018 in stock or June 30, 2018 in index, including reinvestment of dividends.

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Item 6. Selected Financial Data
The following table shows the selected historical financial information, for the periods and as of the dates indicated, of Berry LLC, the predecessor company, and following the Effective Date, Berry Corp. and its subsidiary, Berry LLC, together, the successor company. The selected historical financial information as of and for the year ended December 31, 2019, the year ended December 31, 2018, and the ten months ended December 31, 2017 is derived from audited consolidated financial statements of the successor company. The selected historical financial information as of and for the two months ended February 28, 2017 and the year ended December 31, 2016 is derived from the audited historical financial statements of our predecessor company.
Berry LLC emerged from bankruptcy on February 28, 2017 ("the Effective Date") in connection with "the Plan", which is the reorganization plan approved and confirmed by the Bankruptcy Court in the Chapter 11 Proceeding. On that date Berry LLC adopted fresh-start accounting and was recapitalized, which resulted in Berry LLC becoming a wholly-owned subsidiary of Berry Corp. and Berry Corp. being treated as the new entity for financial reporting. As a result, our consolidated financial statements subsequent to the Effective Date are not comparable to our financial statements prior to such date. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.
 
Berry Corp.
(Successor)
 
 
Berry LLC
(Predecessor)
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
 
(in thousands, except per share amounts)
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
 
Revenues and other
$
559,405

 
$
586,557

 
$
319,669

 
 
$
92,718

 
$
410,991

Net income (loss) attributable to common stockholders(1)(4)
$
43,539

 
$
49,160

 
$
(39,316
)
 
 
$
(502,964
)
 
$
(1,283,196
)
Net income (loss) per share of common stock

 

 

 
 

 
 
Basic
$
0.54

 
$
0.85

 
$
(1.02
)
 
 
n/a

 
n/a

Diluted
$
0.53

 
$
0.85

 
$
(1.02
)
 
 
n/a

 
n/a

Dividends per common share
$
0.48

 
$
0.21

 
$

 
 
$

 
$

Weighted-average common stock outstanding(2)

 

 

 
 

 
 
Basic
81,379

 
57,743

 
38,644

 
 
n/a

 
n/a

Diluted(2)
81,951

 
57,932

 
38,644

 
 
n/a

 
n/a

Cash Flow Data:

 

 

 
 

 
 
Operating activities(3)
$
241,829

 
$
105,471

 
$
107,399

 
 
$
22,431

 
$
13,197

Capital expenditures
$
(223,154
)
 
$
(129,652
)
 
$
(65,479
)
 
 
$
(3,158
)
 
$
(34,796
)
Balance Sheet Data (at period end):

 

 

 
 

 
 
Total assets
$
1,690,198

 
$
1,692,263

 
$
1,546,402

 
 
$
1,561,038

 
$
2,652,050

Long-term debt, net
$
394,319

 
$
391,786

 
$
379,000

 
 
$
400,000

 
$

__________
(1)
Refer to “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” for discussion regarding factors in comparability, such as, impairment of its Piceance gas properties and income taxes in 2019.
(2)
The Series A Preferred Stock was not a participating security; therefore, we calculated diluted earnings per share using the “if-converted” method, under which the preferred dividends are added back to the numerator and the Series A Preferred Stock is assumed to be converted at the beginning of the period. No incremental shares of Series A Preferred Stock were included in the diluted EPS calculation for the years ended December 31, 2019 or 2018, as all outstanding shares of our Series A Preferred (the "Series A Preferred Stock") were converted to common shares (the "Series A Preferred Stock Conversion") in connection with the IPO of our common stock in July 2018. No incremental shares of Series A Preferred Stock were included in the diluted earnings per share calculation for the ten months ended December 31, 2017 as their effect was antidilutive under the “if-converted” method. Please see Note 6 for further detail.

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(3)
2018 includes a one-time payment of $127 million in the second quarter to early terminate unsettled derivative contracts. The elective cancellation was effected to realign our hedging pricing with current market rates and move from WTI to Brent underlying.
(4)
Net Income Attributable to Common Stockholders for year ended December 31, 2019 includes a $51 million non-cash impairment charge for the Piceance gas properties, and $39 million in income tax credits from prior periods.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes included elsewhere in this report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are described in “Item 1A. Risk Factors” included earlier in this report. Please see “Cautionary Note Regarding Forward-Looking Statements.”
This section of the Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between those years. For discussion of our ten months ended December 31, 2017 and two months ended February 28, 2017, as well as the year ended 2018 compared to ten months ended December 31, 2017 and two months ended February 28, 2017, refer to Part II, Item 7— "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our 2018 Annual Report on Form 10-K.
Executive Overview
We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived, oil reserves in conventional reservoirs.
Most of our assets are located in the oil-rich reservoirs in the San Joaquin basin of California, which has more than 100 years of production history and substantial remaining oil in place. As a result of the substantial data produced over the basin's long history, its reservoir characteristics are well understood, leading to predictable, repeatable, low geological risk and low-c and, to a lesser extent, in our Rockies assets which include low-cost, oil-rich reservoirs in the Uinta basin of Utah and low geologic risk natural gas resource plays in the Piceance basin in Colorado. Successful execution of our strategy across our low-declining production base and extensive inventory of identified drilling locations will result in our ability to continue returning capital to our stockholders and demonstrate long-term, capital efficient, consistent, and predictable production growth while living within levered free cash flow.
Effective February 18, 2020, Berry Petroleum Corporation changed its name to Berry Corporation (bry) and introduced a new logo. We believe that the name Berry Corporation (bry) is a name that better represents our progressive approach to evolving and growing the business in today’s dynamic oil and gas industry. We are proactively engaging the many forces driving our industry to maximize our assets, create value for shareholders, and support environmental goals that align with a more positive future. One of the more visible elements of our business is our publicly traded stock, and our new logo echoes the public value of the company by using our ticker symbol as an identifiable element of our brand.
How We Plan and Evaluate Operations
We use Levered Free Cash Flow in planning our capital allocation to sustain production levels and fund internal growth opportunities, as well as determine hedging needs. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense, and dividends.
We use the following metrics to manage and assess the performance of our operations and are part of our incentive program for all employees: (a) Adjusted EBITDA; (b) operating expenses; (c) environmental, health & safety (“EH&S”) results; (d) general and administrative expenses; and (e) production.
Adjusted EBITDA
Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business. We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization (“DD&A”); derivative gains or losses net of cash received or

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paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items.
Operating expenses
We define operating expenses as lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases. Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Taxes other than income taxes are excluded from operating expenses. The electricity, transportation and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economics of development projects and the efficiency of our hydrocarbon recovery. Additionally, we strive to minimize the variability of our fuel gas costs for our steam operations with gas hedges. Overall, operating expense is used by management as a measure of the efficiency with which operations are performing.
Environmental, health & safety
Like other companies in the oil and gas industry, our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Current and future laws and regulations can materially impact our exploration, development and production plans.
We are committed to good corporate citizenship in our communities, operating safely and protecting the environment and our employees. We monitor our EH&S performance through various measures, holding our employees and contractors to high standards.
General and administrative expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities. Such expenses are a key component of the appropriate level of support our corporate and professional team provides to the development of our assets and our day-to-day operations.
Production
Oil and gas production is a key driver of our operating performance, an important factor to the success of our business, and used in forecasting future development economics. We measure and closely monitor production on a continuous basis, adjusting our property development efforts in accordance with the results. We track production by commodity type and compare it to prior periods and expected results.
Business Environment and Market Conditions
The oil and gas industry is heavily influenced by commodity prices. Average oil prices were lower for 2019 compared to 2018 . Brent crude oil contract prices ranged during 2019 from $54.91 per Bbl at the beginning, to a high of $74.57 per Bbl and back to $56.23 per Bbl. In California, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, as well as the SoCal Index which were as low as $0.99 per MMBtu and as high as $22.38 per MMBtu for a short time in 2019 due to market disruptions, while we paid an average of $3.14 for the year. The Henry Hub spot price for natural gas fluctuated between $1.75 per MMBtu and $4.25 per MMBtu, with an average of $2.56 during 2019. Our revenue, costs, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production and the prices we pay for our natural gas purchases which will continue to be affected by a variety of factors. Please see “Item 1A. Risk Factors—Risks Related to Our Business and IndustryOil, natural gas and NGL prices are volatile and directly affect our results.
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