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, 2018
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 PETROLEUM CORPORATION
(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
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.                                 ¨
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
As of June 30, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s equity was not listed on any domestic exchange or over-the-counter market. The registrant’s common stock began trading on the Nasdaq Global Select Market (“NASDAQ”) on July 26, 2018.
Shares of common stock outstanding as of February 28, 2019                             82,061,650
DOCUMENTS INCORPORATED BY REFERENCE
The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 14, 2019) will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2018 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
When we use the terms “we,” “us,” “our,” the “Company,” or similar words in this report, unless the context otherwise requires, on or prior to 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—Lawsuits, Claims, Commitments, and Contingencies”), we are referring to Berry LLC, our predecessor company, and following the Effective Date, we are referring to Berry Corp. and its subsidiary, Berry LLC, together, the successor company, as applicable.
Our Company
We are a western United States independent upstream energy company with a focus on the conventional, long-lived oil reserves in the San Joaquin basin of California. Our long-lived, high-margin asset base is uniquely positioned to support our objectives of generating top-tier corporate-level returns and positive levered free cash flow through commodity price cycles. Successful execution of our strategy across our low-declining production base and extensive inventory of identified drilling locations will result in long-term, capital efficient production growth as well as the ability to continue returning capital to our stockholders.
We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin of California and, to a lesser extent, our Rockies assets including 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. In the aggregate, the Company’s assets are characterized by:
high oil content, which has grown to over 85% of our production;
favorable Brent-influenced crude oil pricing dynamics;
long-lived, conventional reserves with low and predictable production decline rates;
stable development and production cost structures;
an extensive inventory of low-risk identified development drilling opportunities with attractive full-cycle economics; and
potential in-basin organic and strategic opportunities to expand our existing inventory with new locations of substantially similar geology and economics.
California is and has been one of the most productive oil and natural gas regions in the world. Our asset base is concentrated in the oil-rich San Joaquin basin in California, which has more than 100 years of production history, substantial remaining oil in place, and is considered a super basin. As a result of the substantial data produced over the basin's long history, its geological and reservoir characteristics are well understood, leading to predictable, repeatable, low-risk development opportunities.
In California, we focus on conventional, shallow reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. Our decades-old proven completion techniques in these reservoirs include cyclic and continuous steam injection and low-volume hydraulic stimulation. 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 operations will average $1.3 million per well.
As noted, we own additional assets in the Uinta basin in Utah, a mature, light-oil-prone play with significant undeveloped resources where we have high operational control and additional behind pipe potential, as well as in the Piceance basin in Colorado, a prolific low geologic risk natural gas play where we produce from a conventional, tight

1

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Index to Financial Statements and Supplementary Data

sandstone reservoir using proven slick water stimulation techniques to increase recoveries. On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
As of December 31, 2018, we had estimated total proved reserves of 142,720 MBoe. For the year ended December 31, 2018, we had average production of approximately 27.0 MBoe/d, of which approximately 82% was oil. For the three months ended December 31, 2018, we had average production of approximately 28.0 MBoe/d, of which approximately 85% was oil. In California, our average production for the year and the quarter ended December 31, 2018 was 19.7 MBoe/d and 21.7 MBoe/d, respectively, of which approximately 100% was oil.
The Berry Advantage
We believe that our combination of low production decline rates, high-margin Brent-influenced oil-weighted production, attractive development opportunities and a stable cost environment differentiates us from our competitors and allows us to break even on a cash flow basis and maintain production at relatively low commodity prices. Our advantages give us an ability to generate top-tier corporate level returns, positive Levered Free Cash Flow and capital-efficient growth through commodity price cycles. “Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less interest expense, dividends and capital expenditures.
Our Low Declining Production Base
Our California reserves are predominantly long-lived and characterized by relatively low production decline rates and development costs, affording us 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 19% to 11% in the years between 2019 and 2024 based on total PDP Boe reserves as of December 31, 2018 as reflected in our SEC reserves report, which is attached as Exhibit 99.1. Our SEC reserves report is based on the estimated individual well production profiles used to determine our PDP reserves. Based on the assumptions underlying our PUD estimates, we estimate that we will require slightly more than $10 per Boe in annual capital expenditures to keep production volumes consistent each year over the next three years. In addition to our low and stable cash operating costs, which were approximately $26 per Boe in 2018, we can operate and maintain production at relatively low commodity price levels. Considering our typical realized prices, we believe our operations break even when crude prices are at or above $45 Brent.
Our High-Margin Brent-Influenced Oil-Weighted Production
Our highly oil-weighted production combined with a Brent-influenced California pricing dynamic and stable cost structure has resulted, and is expected to continue to result, in strong operating margins at current commodity prices. As of December 31, 2018, our California PUD reserves were 100% oil.
Our Stable California Operating and Development Cost Environment
The operating and development cost structures of our conventional California asset base are inherently stable and predictable. Our California focus has insulated us from the cost inflation pressures experienced by our peers who operate primarily in unconventional plays. This is the result of our established infrastructure, low-intensity service requirements and lack of dependence on inventory-constrained and often highly specialized equipment. In addition, the majority of our California assets are located in the fields of the San Joaquin basin and are characterized by heavy oil found in shallow reservoirs. The costs to develop these reservoirs are lower when compared to the water flood fields of the Los Angeles and Ventura basins.

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Index to Financial Statements and Supplementary Data

Our Reserves and Assets
As of December 31, 2018, we had estimated total proved reserves of 142,720 MBoe. For the year ended December 31, 2018, we had average production of approximately 27.0 MBoe/d, of which approximately 82% was oil. For the three months ended December 31, 2018, we had average production of approximately 28.0 MBoe/d, of which approximately 85% was oil. In California, our average production for the year and the quarter ended December 31, 2018 was 19.7 MBoe/d and 21.7 MBoe/d, respectively, of which approximately 100% was oil.
The majority of our reserves are composed of heavy crude oil in shallow, long-lived reservoirs. As of December 31, 2018, approximately three quarters of our proved reserves and approximately 94% 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. On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
As of December 31, 2018, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our proved reserves were approximately $1.8 billion and $2.2 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 “—Our Reserves and Production Information—PV-10”.
The tables below summarize our proved reserves and PV-10 by category as of December 31, 2018:
 
Proved Reserves as of December 31, 2018(1)
 
Oil (MMBbl)
 
Natural Gas (Bcf)
 
NGLs (MMBbl)
 
Total (MMBoe)
 
% of Proved
 
% Proved Developed
 
Capex(2) ($MM)
 
PV-10(3) ($MM)
PDP
62

 
76

 
1

 
76

 
53
%
 
87
%
 
$
35

 
$
1,263

PDNP
11

 

 

 
11

 
8
%
 
13
%
 
24

 
248

PUD
42

 
85

 

 
56

 
39
%
 
%
 
683

 
641

Total
115

 
161

 
1

 
143

 
100
%
 
100
%
 
$
742

 
$
2,152

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
California
106

 

 

 
106

 
N/A

 
N/A

 
$
603

 
$
2,027

__________
(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 $71.54 per Bbl Intercontinental Exchange (“ICE”) Brent oil (“Brent”) for oil and natural gas liquids (“NGLs”) and $3.10 per MMBtu New York Mercantile Exchange (“NYMEX”) Henry Hub (“Henry Hub”) for natural gas at December 31, 2018. The volume-weighted average prices over the lives of the properties were estimated at $66.49 per Bbl of oil and condensate, $32.87 per Bbl of NGLs and $2.806 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)
Represents undiscounted future capital expenditures estimated as of December 31, 2018.
(3)
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.


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Index to Financial Statements and Supplementary Data

The table below summarizes our average net daily production by basin for the year ended December 31, 2018:
 
Average Net Daily Production(1)
for the Year Ended
 
December 31, 2018
 
(MBoe/d)
 
Oil (%)
California
19.7

 
100
%
Rockies
7.3

 
32
%
Total
27.0

 
82
%
__________
(1)    Production represents volumes sold during the period.

Our Development Inventory
We have an extensive inventory of low-risk, high-return development opportunities. As of December 31, 2018, we identified 3,314 gross drilling locations company-wide that we anticipate drilling over the next 5 to 10 years, which we refer to as our “Tier 1” locations, and 3,716 additional gross drilling locations that are currently under review. For a discussion of how we identify drilling locations, please see “—Our Reserves and Production Information—Determination of Identified Drilling Locations.”
We operate approximately 98% of our producing wells. In addition, approximately 75% of our acreage is held by production, including 99% of our acreage in California. The combined net acreage covered by leases expiring in the next three years represented approximately 5% of our total net acreage at December 31, 2018. 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 operations as of December 31, 2018:
 
Acreage
 
Net Acreage Held By Production(%)
 
Producing Wells, Gross(1)(2)
 
Average Working Interest (%)(2)(3)
 
Net Revenue Interest (%)(2)(4)
 
Identified Drilling Locations(5)
 
Gross
 
Net
 
 
Gross
 
Net
California
11,268

 
8,333

 
99
%
 
2,698

 
99
%
 
93
%
 
4,923

 
4,915

Rockies
134,470

 
100,126

 
73
%
 
1,105

 
94
%
 
75
%
 
2,107

 
1,747

Total
145,738

 
108,459

 
75
%
 
3,803

 
98
%
 
89
%
 
7,030

 
6,662

__________
(1)
Includes 540 steamflood and waterflood injection wells in California.
(2)
Excludes 91 wells in the Piceance basin each with a 5% working interest.
(3)
Represents our weighted-average working interest in our active wells.
(4)
Represents our weighted-average net revenue interest for the year ended December 31, 2018.
(5)
Our total identified drilling locations include approximately 1,071 gross (1,058 net) locations associated with PUDs as of December 31, 2018, including 88 gross (88 net) steamflood injection wells. Please see “—Our Reserves and Production Information—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations.

Our Competitive Strengths
We believe that the following competitive strengths will allow us to successfully execute our business strategy.
Stable, low-decline, predictable and oil-weighted conventional asset base. The majority of our interests are in properties that have produced 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 cost structure and low-risk developmental drilling opportunities with

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Index to Financial Statements and Supplementary Data

predictable production profiles. The nature of our assets provides us with a high degree of capital flexibility through commodity cycles.
Substantial inventory of low-cost, low-risk and high-return development opportunities. We expect our locations to generate highly attractive rates of return. For example, our PUD reserves in California are projected to average single-well rates of return of approximately 39% based on the assumptions used in preparing our SEC reserves report as of December 31, 2018.
Brent-influenced pricing advantage. California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from foreign 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.
Substantial capital flexibility derived from a high degree of operational control and stable cost environment. We operate over 95% of our producing wells and expect to operate a similar percentage of our identified gross drilling locations. In addition, approximately 75% of our acreage is held by production, including 99% of our acreage in California. Our high degree of operational control over our properties, together with the large portion of our acreage that is held by production, gives us flexibility in executing our development program, including the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of production. We expect our operations to continue to generate positive Levered Free Cash Flow at current commodity prices allowing us to return capital to stockholders and fund maintenance operations and growth among other things. 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 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.
Simple capital structure and conservative balance sheet leverage with ample liquidity and minimal contractual obligations. In connection with our 2018 IPO, we converted all of our Series A Preferred Stock (the “Series A Preferred Stock”) into common stock (the “Series A Preferred Stock Conversion”). Earlier in 2018, we closed a private offering of $400 million in aggregate principal amount of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. As of December 31, 2018, we had $462 million of available liquidity, defined as cash on hand plus availability under the $1.5 billion 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.
Ability and intention to return capital to stockholders consistently through the commodity price cycle. We generated positive Levered Free Cash Flow in 2018 when Brent oil prices ranged from a mid-year high of $86.29 to a low of $50.47 toward the end of the year. In California, we believe our operations break even when Brent crude prices are approximately $47 per barrel, meaning we expect to have positive Levered Free Cash Flow at that level. We have paid a dividend on our common stock since our first quarter as a public company and plan to continue paying a meaningful quarterly dividend.
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 cost advantage.

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Our Business Strategy
The principal elements of our business strategy include the following:
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-risk development opportunities while focusing on driving cost 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.
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 explore innovative EOR techniques to unlock additional value and have allocated capital towards next generation technologies. For example, in our South Belridge Hill non-thermal and Midway-Sunset thermal Diatomite properties, we employ both hydraulic stimulation and advanced thermal techniques, and in our Piceance properties, we use advanced proppantless slick water well stimulation techniques. 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.
Proactively and collaboratively engage in matters related to regulation, safety, environmental and community relations. We are committed to proactive engagement with regulatory agencies 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 work closely with regulators and legislators throughout the rule making process to minimize adverse impacts that new legislation and regulations might have on our ability to maximize our resources and to facilitate our permitting process. We have found constructive dialogue with regulatory agencies can help avert compliance and permitting issues. By working with the legislators and regulators on the front end of the regulatory process, our goal is to minimize the impact of new regulations and legislation and to mitigate the risk of permitting delays.
Return excess free cash flow to stockholders. Our objective is to implement a disciplined and returns-focused approach to capital allocation in order to generate excess free cash flow. We intend to return portions of that excess free cash flow to stockholders on a quarterly basis. 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, please see “Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity SecuritiesDividend Policy.”
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 de-lever 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 1.5x and 2.0x.
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 portion of our anticipated crude oil production realizations into 2020. We will review our hedging program continuously as conditions change.

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Our Capital Budget
Immediately following Berry LLC’s emergence from bankruptcy and separation from Linn Energy, LLC (“Linn Energy”) and LinnCo, LLC (“LinnCo” and, together with Linn Energy, the “Linn Entities”) in 2017, we increased our pace of development and have continued to do so throughout 2018 and into 2019. For the years ended December 31, 2018 and 2017, our capital expenditures were approximately $148 million and $73 million, respectively, on an accrual basis excluding acquisitions. Our 2019 anticipated capital expenditure budget is approximately $195 to $225 million, which represents an increase of approximately 42% over 2018 capital expenditures. Capital expenditures increased 103% from 2017 to 2018. Based on current commodity prices and a drilling success rate comparable to our historical performance, we believe we will be able to fund our 2019 capital development programs while producing positive Levered Free Cash Flow. Our 2019 capital program is focused on growing our oil production in California. We anticipate oil production will be approximately 86% of total production in 2019, compared to 82% in 2018. This change in product mix was also a factor in the divestiture of our non-core East Texas gas properties in late 2018. During 2019, we expect to:
employ four drilling rigs in California throughout the year; and
drill approximately 370 to 420 gross development wells, all of which we expect will be in California for oil production.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these 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 availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners, as well as general market conditions. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial condition and results of operations. For additional information about the 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 OperationsFactors Affecting the Comparability of Our Financial Condition and Results of OperationsCapital Expenditures and Capital Budget”.
Our Areas of Operation
Our predominant operating area is in California, and we also have operations in the Rockies. On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
California
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 the three fields —Midway-Sunset and South Belridge. California is and has been one of the most productive oil regions in the world, and is currently ranked as the third largest state in reserves and sixth largest state in production in the U.S.
In California, we actively operate and develop properties located in the Midway-Sunset, South Belridge, McKittrick and Poso Creek fields in the San Joaquin basin in Kern County as well as the Placerita Field in the Ventura basin in Los Angeles County. We currently hold 8,333 net acres in these basins with a 99% average working interest. The producing areas in our Southeast San Joaquin operations include: (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. The producing areas in our Northwest San Joaquin operations include: (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,

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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. Our California proved reserves represented approximately 74% of our total proved reserves at December 31, 2018 and accounted for 19.7 MBoe/d or 73% of our average daily production for the year ended December 31, 2018 and 21.7 MBoe/d or 78% of our average daily production for the three months ended December 31, 2018.
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 assist in this operation, we own and operate five natural gas cogeneration plants that produce steam. These plants supply approximately 24% of our steam needs and approximately 63% of our field electricity needs in California at a discount to electricity market prices. To further 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 and operate 79 conventional steam generators.
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 80% of our California oil production is sold through pipeline connections, and we have contracts in place with third-party purchasers of our crude.
According to the Division of Oil, Gas, and Geothermal Resources of the California Department of Conservation (“DOGGR”), approximately 76% of California’s daily oil production of 477 MBbl/d for 2017 was produced in the San Joaquin basin. 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. We began operations in California 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. We believe there are extensive existing field redevelopment opportunities in our areas of operation within the San Joaquin basin. We believe that our California focus and strong balance sheet will allow us to take advantage of these opportunities.
Rockies
Uinta basin

Our Uinta basin operations in the Brundage Canyon, Ashley Forest and Lake Canyon areas 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 13% of our total proved reserves at December 31, 2018 and accounted for 4.9 MBoe/d or 18% of our average daily production for the year ended December 31, 2018.
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

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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 93 MBbl/d in 2017. Approximately 82% of Utah’s production in 2017 came from the Uinta basin in Duchesne and Uintah counties.
Piceance basin

Our primary operating areas in the Piceance basin are Garden Gulch and North Parachute 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 13% of our total proved reserves at December 31, 2018 and accounted for 1.7 MBoe/d or 6% of our average daily production for the year ended December 31, 2018.
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 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.


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Methods of Recovery
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 a high working interest and operating control in our properties.
Our California operations are primarily focused on the Hill Diatomite, thermal Diatomite and thermal Sandstones 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
 
Tier 1
 
Additional
 
Total
California
 
Hill Diatomite (non-thermal)
 
Vertical
 
Low intensity pin point
 
Pressure depletion augmented with water injection
 
272
 
585
 
857
California
 
Thermal Diatomite
 
Vertical
 
Short interval perforations
 
Cyclic steam injection
 
787
 
979
 
1,766
California
 
Thermal Sandstones
 
Vertical / Horizontal
 
Perforation/Slotted liner/gravel pack
 
Continuous and cyclic steam injection
 
1,811
 
489
 
2,300
Utah
 
Uinta
 
Vertical / Horizontal
 
Low intensity hydraulic stimulation
 
Pressure depletion
 
444
 
793
 
1,237
Colorado
 
Piceance
 
Vertical
 
Proppantless slick water stimulation
 
Pressure depletion
 
 
870
 
870
Total
 
 
 
 
 
 
 
 
 
3,314
 
3,716
 
7,030
__________
(1)
We had 1,071 gross (1,058 net) locations associated with PUDs as of December 31, 2018 including 88 gross (88 net) steamflood injection wells. Of those 1,071 gross PUD locations, 977 are associated with projects in California, 55 are associated with the Piceance basin, and 39 are associated with the Uinta basin. Please see “—Our Reserves and Production Information—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, 2018, we drilled 121 gross (121 net) wells that were associated with PUDs at December 31, 2017, including 27 gross (27 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 steam injection 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 $350,000 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

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referred to as combined heat and power plants, use hot turbine exhaust to produce steam while generating electrical power. This combined process is more efficient than producing power or steam separately. For more information please see “—Electricity.” and “Item 1A. Risk Factors—Risks Related to Our Business and Industry—We are dependent on our cogeneration facilities to produce steam for our operations. Viable 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 79 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 147,000 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 325,000 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 2018 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 and electricity.

Crude Oil. Approximately 80% 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 more than 50% of the state’s demand from foreign sources. This dynamic has led to periods 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, 2018, 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.
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, 2018, 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 entered into natural gas processing contracts whereby the residual natural gas is sold under short-term contracts but

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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.
Electricity
Generation. Our cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. The total 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 costs in our heavy oil operations and to secure operating control of our steam generation.
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 2019 and 2022.
Electricity and steam produced from our Pan Fee and 21Z cogeneration facilities are used solely for field operations with one facility being run at a time and the other acting as 100% backup for the power produced on the lease.

For the year ended December 31, 2018, we sold approximately 1,800 megawatt-hours (“MWhs”) per day and consumed approximately 300 MWhs per day of electricity generated by our five cogeneration facilities. In addition, the five cogeneration facilities produced an average of approximately 35,000 barrels of steam per day.

Principal Customers
For the year ended December 31, 2018, sales to Andeavor, Phillips 66 and Kern Oil & Refining accounted for approximately 35%, 28%, and 13% respectively, of our sales. At December 31, 2018, trade accounts receivable from three customers represented approximately 26%, 22% and 10% 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”.
Our Reserves and Production Information
Reserve Data
The following table summarizes our estimated proved reserves and related PV-10 as of December 31, 2018. 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, 2018(1)
 
California
(San Joaquin and Ventura basins)
 
Rockies
(Uinta and Piceance basins)
 
Total
Proved developed reserves:
 
 
 
 
 
Oil (MMBbl)
66

 
7

 
73

Natural Gas (Bcf)

 
76

 
76

NGLs (MMBbl)

 
1

 
1

Total (MMBoe)(2)(3)
66

 
21

 
87

Proved undeveloped reserves:
 
 
 
 
 
Oil (MMBbl)
40

 
2

 
42

Natural Gas (Bcf)

 
85

 
85

NGLs (MMBbl)

 

 

Total (MMBoe)(3)
40

 
16

 
56

Total proved reserves:
 
 
 
 
 
Oil (MMBbl)
106

 
9

 
115

Natural Gas (Bcf)

 
161

 
161

NGLs (MMBbl)

 
1

 
1

Total (MMBoe)(3)
106

 
37

 
143

 
 
 
 
 
 
PV-10 ($MM)(4)
$
2,027

 
$
125

 
$
2,152

__________
(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 $71.54 per Bbl ICE (Brent) for oil and NGLs and $3.10 per MMBtu NYMEX (Henry Hub) for natural gas at December 31, 2018. The volume-weighted average prices over the lives of the properties were $66.49 per Bbl of oil and condensate, $32.87 per Bbl of NGLs and $2.806 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 9% of proved developed oil reserves, 1% of proved developed NGL reserves, 0% of proved developed natural gas reserves and 8% 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, 2018, the average prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 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. Calculation of PV-10 does not give effect to derivatives transactions. 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, 2018:
 
At December 31, 2018
 
(in millions)
California PV-10
$
2,027

Rockies PV-10
125

Total Company PV-10
2,152

Less: present value of future income taxes discounted at 10%
(390)

Standardized measure of discounted future net cash flows
$
1,762

Proved Reserves Additions
The total changes to our proved reserves from December 31, 2017 to December 31, 2018 were as follows:
 
California (San Joaquin and Ventura basins)
 
Rockies (Uinta and Piceance basins)
 
East Texas basin(1)
 
Total
 
(in MMBoe)
Beginning balance as of December 31, 2017
93

 
46

 
2

 
141

Extensions and discoveries
19

 
3

 

 
22

Revisions of previous estimates

 
(10
)
 

 
(10
)
Purchases of minerals in place
1

 

 

 
1

Sales of minerals in place

 

 
(2
)
 
(2
)
Current year production
(7
)
 
(3
)
 

 
(10
)
Ending balance as of December 31, 2018
106

 
37

 

 
143

__________
Note: 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, 2018, the average prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.
(1)
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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Extensions and Discoveries. During 2018 we added 22 MMBoe of proved reserves from extensions and discoveries principally in our California properties, most of which was thermal Diatomite, as well as in Utah.
Revisions of Previous Estimates.
Revisions related to price - Product price changes affect the proved reserves we record. For example, higher prices generally increase the economically recoverable reserves in all of our operations because the extra margin extends their expected lives and renders more projects economic. Conversely, when prices drop, we experience the opposite effects. In 2018, our total net positive price revision was 8 MMBoe, which was primarily the result of higher prices in the commodity price environment in 2018 compared to 2017.
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 2018, our net negative performance-related revision of 18 MMBoe resulted from negative revisions of 9 MMBoe to remove proved undeveloped reserves due to a downward adjustment of our committed capital in the Piceance basin and technical revisions of 9 MMBoe due to a shift in the development strategy as laid out in our 5-year capital plan, predominantly in the 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 Additions
The total changes to our proved undeveloped reserves from December 31, 2017 to December 31, 2018 were as follows:
 
California (San Joaquin and Ventura basins)
 
Rockies (Uinta and Piceance basins)
 
East Texas basin
 
Total
 
(in MMBoe)
Beginning balance as of December 31, 2017
32

 
23

 

 
55

Extensions and discoveries
17

 
2

 

 
19

Revisions of previous estimates
(1
)
 
(10
)
 

 
(11
)
Reclassifications to proved developed
(9
)
 

 

 
(9
)
Purchases of minerals in place
1

 

 

 
1

Ending balance as of December 31, 2018
40

 
15

 

 
55

__________
Note: 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, 2018, the average prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.

Extensions and Discoveries. During 2018 we added 19 MMBoe of proved undeveloped reserves from extensions and discoveries due to drilling unproven locations in Midway Sunset and Uinta. We also added proven undeveloped reserves for our thermal Diatomite, Buena Fe and Uinta locations.
Revisions of previous estimates.
Revisions related to price - In 2018, our net positive price revision on proven undeveloped reserves was 1 MMBoe, which was primarily the result of higher prices due to the current commodity price environment.

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Revisions related to performance - In 2018, our net negative performance-related revision on proven undeveloped reserves was 12 MMBoe, which resulted primarily from the removal of 9 MMBoe in proved undeveloped reserves due to a downward adjustment of our committed capital in the Piceance basin and technical revisions of 2 MMBoe due to a shift in the development strategy as laid out in our 5-year capital plan, predominantly in the thermal Diatomite area.
Reclassifications to proved developed. Through the 2018 drilling program, we transferred 9 MMBoe of proved undeveloped reserves to the proved developed category in California. As a result, we converted 16% of our beginning-of-the year inventory of proved undeveloped reserves, spending approximately $36 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 $65 to $75 per barrel and average Henry Hub gas prices of at least $3.00 per mcf, we expect to have sufficient future capital to develop our proved undeveloped reserves at December 31, 2018 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 realized 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, who has a Masters in Geology from the University of South Carolina and a Bachelors in Geology from Carleton College, and more than 31 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 33 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.

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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.
Determination of Identified Drilling Locations
Proven Drilling Locations

Based on our reserves report as of December 31, 2018, we have approximately 1,071 gross (1,058 net) drilling locations attributable to our proved undeveloped reserves. 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 5,959 gross (5,604 net) drilling locations that are not associated with our proved undeveloped reserves but 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

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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.
The table below sets forth our PUD locations and total identified drilling locations as of December 31, 2018.
 
PUD Locations
(Gross)
 
Total Identified Drilling Locations (Gross)(1)
 
Oil and Natural Gas Wells
 
Injection
Wells
 
Oil and Natural Gas Wells
 
Injection
Wells
California
889

 
88

 
4,141

 
782

Rockies
94

 

 
2,107

 

Total Identified Drilling Locations
983

 
88

 
6,248

 
782

__________
(1)
Includes 3,314 Tier 1 gross drilling locations company-wide that we anticipate drilling over the next 5 to 10 years and 3,716 additional gross drilling locations that are currently under review.

Production and Operating Data
The following table sets forth information regarding production, realized and benchmark prices, and production costs for the year ended December 31, 2018, the ten months ended December 31, 2017, the two months ended February 28, 2017, and the year ended December 31, 2016.

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Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
Production Data(3):
 
 
 
 
 
 
 
 
Oil (MBbl/d)
22.0

 
20.6

 
 
19.5

 
23.1

Natural gas (MMcf/d)
26.3

 
49.4

 
 
71.7

 
78.1

NGLs (MBbl/d)
0.6

 
2.0

 
 
5.2

 
3.6

Average daily combined production (MBoe/d)(1)
27.0

 
30.9

 
 
36.7

 
39.7

Oil (MBbl)
8,045

 
6,318

 
 
1,153

 
8,463

Natural gas (MMcf)
9,589

 
15,119

 
 
4,232

 
28,577

NGLs (MBbl)
211

 
605

 
 
304

 
1,307

Total combined production (MBoe)(1)
9,855

 
9,443

 
 
2,162

 
14,533

Weighted-average realized prices:
 
 
 
 
 
 
 
 
Oil with hedges (per Bbl)
$
59.67

 
$
48.53

 
 
$
47.40

 
$
36.88

Oil without hedges (per Bbl)
$
64.76

 
$
48.05

 
 
$
46.94

 
$
35.83

Natural gas (per Mcf)
$
2.74

 
$
2.70

 
 
$
3.42

 
$
2.31

NGLs (per Bbl)
$
26.74

 
$
22.23

 
 
$
18.20

 
$
17.67

Average Benchmark prices:
 
 
 
 
 
 
 
 
Oil (per Bbl) – Brent
$
71.53

 
$
54.65

 
 
$
55.72

 
$
45.00

Oil (per Bbl) – WTI
$
64.76

 
$
50.53

 
 
$
53.04

 
$
43.32

Natural gas (per MMBtu) – Henry Hub
$
3.09

 
$
3.00

 
 
$
3.66

 
$
2.46

Total operating expenses (per Boe)(2)
$
18.33

 
$
17.09

 
 
$
15.72

 
$
15.13

Taxes, other than income taxes (per Boe)
$
3.36

 
$
3.62

 
 
$
2.41

 
$
1.73

__________
(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, 2018, the average prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis.
(2)
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. Taxes other than income taxes are excluded from operating expenses.
(3)
Production represents volumes sold during the period.

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, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
SJV South Midway Field
 
 
 
 
 
 
 
 
Total production(2):
 
 
 
 
 
 
 
 
Oil (MBbls)
2,341

 
1,963

 
 
369

 
2,477

Natural gas (Bcf)

 

 
 

 

NGLs (MBbls)

 

 
 

 

Total (MBoe)(3)
2,341

 
1,963

 
 
369

 
2,477


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Index to Financial Statements and Supplementary Data

 
Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
SJV Belridge Hill(4)
 
 
 
 
 
 
 
 
Total production(2):
 
 
 
 
 
 
 
 
Oil (MBbls)
*
 
609

 
 
35

 
*
Natural gas (Bcf)
*
 

 
 

 
*
NGLs (MBbls)
*
 

 
 

 
*
Total (MBoe)(3)
*
 
609

 
 
35

 
*
 
Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
Piceance
 
 
 
 
 
 
 
 
Total production(2):
 
 
 
 
 
 
 
 
Oil (MBbls)
*
 
14

 
 
2

 
*
Natural gas (Bcf)
*
 
3.6

 
 
0.8

 
*
NGLs (MBbls)
*
 

 
 

 
*
Total (MBoe)(3)
*
 
610

 
 
138

 
*
 
Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
Year Ended December 31, 2018
 
Ten Months Ended December 31, 2017
 
 
Two Months Ended February 28, 2017
 
Year Ended December 31, 2016
Hugoton basin Field(1)
 
 
 
 
 
 
 
 
Total production(2):
 
 
 
 
 
 
 
 
Oil (MBbls)
*
 
*
 
 
*
 

Natural gas (Bcf)
*
 
*
 
 
*
 
14.6

NGLs (MBbls)
*
 
*
 
 
*
 
1,020

Total (MBoe)(3)
*
 
*
 
 
*
 
3,457

__________
*
Represented less than 15% of our total proved reserves for the periods indicated.
(1)
On July 31, 2017, we sold our approximately 78% non-operated working interest in the Hugoton natural gas field. No production data is available for periods following the disposition.
(2)
Production represents volumes sold during the period.
(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, 2018, the average prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1.
(4)
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, 2018, we had a total of 4,029 gross (3,743 net) productive wells (including 540 gross and net steamflood and waterflood injection wells), approximately 96% 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.

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The following table sets forth our productive oil and natural gas wells (both producing and capable of producing) as of December 31, 2018.
 
California
(San Joaquin and Ventura basins)
 
Rockies
(Uinta and Piceance basins)
 
Total
Oil
 
 
 
 
 
Gross(1)
2,921

 
935
 
3,856
Net(2)
2,775

 
844
 
3,619
Gas
 
 
 
 

Gross(1)

 
173
 
173
Net(2)

 
124
 
124
__________
(1)
The total number of wells in which interests are owned. Includes 540 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, 2018. Approximately 75% of our leased acreage was held by production at December 31, 2018.
 
California
(San Joaquin and Ventura basins)
 
Rockies
(Uinta and Piceance basins)
 
Total
Developed(1)
 
 
 
 
 
Gross(2)
11,148
 
95,103
 
106,251
Net(3)
8,212
 
72,944
 
81,156
Undeveloped(4)
 
 
 
 
 
Gross(2)
120
 
39,366
 
39,486
Net(3)
120
 
27,182
 
27,302
__________
(1)
Acres spaced or assigned to productive wells.
(2)
Total acres in which we hold an interest.
(3)
Sum of fractional interests owned based on working interests or interests under arrangements similar to production sharing contracts.
(4)
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the acreage contains proved reserves.

Participation in Wells Being Drilled
The following table sets forth our participation in wells being drilled as of December 31, 2018.
 
California
(San Joaquin and Ventura basins)
 
Rockies
(Uinta and Piceance basins)
 
Total
Development wells
 
 
 
 
 
Gross
3

 

 
3

Net
3

 

 
3

Exploratory wells
 
 
 
 


Gross

 

 

Net

 

 



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At December 31, 2018, 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)
 
Rockies
(Uinta and Piceance basins)
 
Total
2018
 
 
 
 
 
Oil(2)
224

 
8

 
232

Natural Gas

 

 

Dry

 

 

2017
 
 
 
 
 
Oil(1)
124

 

 
124

Natural Gas

 

 

Dry

 

 

2016
 
 
 
 
 
Oil(1)
11

 

 
11

Natural Gas

 

 

Dry

 

 

__________
(1)
Includes injector wells.
(2)
Includes 40 drilled uncompleted wells in California, 12 wells that had not yet been connected to gathering systems in California and six wells that had not yet been connected to gathering systems in the Rockies.

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, 2018, the volumes contracted to be delivered were approximately 9,460 MMBtu/d of gas beginning in 2019 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.
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 independent operators and master limited partnerships 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.
Seasonality
Seasonal weather conditions can impact a portion of 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 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 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 portion of the gas we expect to consume.
Regulation of Health, Safety and Environmental Matters
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. Our operations are subject to the same environmental laws and regulations as other companies in the oil and natural gas industry. These laws and regulations may:
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;
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

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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.
For example, in 2014, DOGGR began a detailed review of the multi-decade practice of permitting underground injection wells under the Safe Drinking Water Act (the “SDWA”). The purpose of the review was to ensure that wastewater is not injected into formations that could be a future source of drinking water supply. In 2015, the state set deadlines to obtain confirmation of aquifer exemptions under the SDWA in certain formations in certain fields from the United States Environmental Protection Agency (the “EPA”). Several industry groups challenged DOGGR’s implementation of its aquifer exemption regulations, and, in March 2017, the Kern County Superior Court issued an injunction barring the blanket enforcements of DOGGR’s aquifer exemption regulations. The court held that DOGGR must show that an underground injection well’s operations have caused an actual harm and go through a hearing process before the agency can issue fines or shut down operations.
In addition, DOGGR has proposed new underground injection regulations in July 2018. The proposed rules would impose additional requirements related to injection approvals, project data requirements, mechanical integrity testing of injection wells, monitoring requirements, prevention of surface expressions, incident response, and monitoring seismic activity. To date, restrictions on underground injection have not affected our oil and natural gas production in any material way. Separately, the state began a review in 2015 of permitted surface discharge of produced water, which led to additional permitting requirements in 2017 for surface discharge of produced water. Government authorities may ultimately restrict injection of produced water or other fluids in additional formations or certain wells, restrict the surface discharge or use of produced water or take other administrative actions. The foregoing reviews could also give rise to litigation with government authorities and third parties.
These laws, rules and regulations may also restrict the production rate of oil, natural gas and NGLs below the rate that would otherwise be possible. 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 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;

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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. 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.
Climate Change
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted three sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles, a second that regulates emissions of GHGs from certain large stationary sources under the CAA’s Prevention of Significant Deterioration and Title V permitting programs, and a third that regulates GHG emissions from fossil fuel-burning power plants, although future implementation of this rule as it applies to existing power plants is uncertain at this time due to ongoing litigation and reconsideration of the rule by the current administration.
The EPA and the California Air Resources Board (“CARB”) have also expanded direct regulation of methane emissions. In June 2016, the EPA finalized rules that establish new controls for emissions of methane (a GHG considered

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more potent than carbon dioxide) from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore oil and natural gas production facilities, on an annual basis. However, in March 2018 EPA finalized several amendments to the 2016 rule, including rolling back a requirement to repair leaking components during unplanned or emergency shutdowns. Also, in September 2018, the EPA issued proposed revisions to the 2016 methane rules, which would reduce the monitoring obligations for wells and compressor stations and exempting previously covered equipment at certain locations. Separately, the U.S. Bureau of Land Management (the “BLM”) previously finalized similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but issued a final rule repealing those standards in September 2018. Several states and environmental groups have announced their intent to file judicial challenges against any attempt to repeal or revise the EPA and BLM methane rules. As a result, future implementation of both the EPA and BLM methane rules is uncertain at this time.
Additionally, CARB has promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production, pipeline gathering and boosting station assets, and natural gas processing plant operations beginning in 2018 and additional controls such as vapor recovery to capture methane emissions in subsequent years. Colorado has also imposed similar regulations governing methane emissions that could impact our operations in the Piceance basin.
In addition, on September 10, 2018, the Governor of California signed into law a bill that would commit California, the fifth largest economy in the world, to the use of 100% zero-carbon electricity by 2045. The same day, the Governor also signed an executive order committing California to total economy-wide carbon neutrality by 2045, including in transportation, building heating and cooling, and industry. The law does not directly affect the oil and gas industry, and it remains unclear what actions state agencies may take in response to executive order. In any event, these recent actions could result in decreased future demand for our products to meet energy needs and in turn have an adverse effect on our business and results of operations. Legislation and regulation to address climate change could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas and other products produced by us, and potentially lower the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. In addition, several municipalities and counties in various states have filed lawsuits against fossil fuel energy companies to address concerns such as coastal erosion and other alleged climate-related damage.
In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in 2017 the Trump administration indicated that the United States would be withdrawing from participation in the Paris Agreement. There has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, almost one half of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs, including by means of cap-and-trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. See “—California GHG Regulations” below for additional details on current GHG regulations in the State of California. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on or limiting emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce.
Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our

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operations. For more information, please see “Item 1A. Risk Factors—Risks Related to Our Business and IndustryConcerns about climate change and other air quality issues may affect our operations or results;” and “—Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including 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.
California GHG Regulations
In October 2006, California adopted the Global Warming Solutions Act of 2006, which established a statewide “cap-and-trade” program with an enforceable compliance obligation beginning with 2013 GHG emissions and ending in 2020. The state has also established a low carbon fuel standard that encourages the use of fuels with lower carbon intensities instead of traditional fossil fuels. In July 2017, California extended its cap-and-trade program through 2030. The program is designed to reduce the state’s GHG emissions to 1990 levels by 2020 and to reduce the state’s GHG emissions to at least 40% below 1990 levels by 2030. The California cap-and-trade program sets maximum limits or caps on total emissions of GHGs from industrial sectors of which we are a part, as our California operations emit GHGs. The cap will decline annually through 2030. We are required to remit compliance instruments for each metric ton of GHG that we emit, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. Under the cap-and-trade program, we will be granted a certain number of California carbon allowances (“CCA”) and we will need to purchase CCAs and/or offset credits to cover the remaining amount of our emissions. Compliance with the California cap-and-trade program laws and regulations could significantly increase our capital, compliance and operating costs and could also reduce demand for the oil and natural gas we produce. The cost to acquire compliance instruments will depend on the market price for such instruments at the time they are purchased, the distribution of cost-free allowances among various industry sectors by the CARB and our ability to limit our GHG emissions and implement cost-containment measures.
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. Further, in March 2015, the BLM adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic stimulation operations after activity has been completed and would strengthen standards for well-bore integrity and management of fluids that return to the surface during and after stimulations on federal and Indian lands. On December 29, 2017 the BLM formally rescinded the 2015 rule governing hydraulic stimulation operations on public and tribal lands. The 2015 rule included a comprehensive set of well-bore integrity requirements, standards for the interim storage of recovered waste fluids, mandatory notifications and waiting periods for key parts of the stimulation process, and chemical disclosure requirements. On January 24, 2018, California and a coalition of environmental and tribal groups each filed lawsuits in the Northern District of California to challenge BLM’s rescission of the 2015 rule. 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 operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.

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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, certain states in which we operate have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic stimulation fluids. In addition, 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, most recently, new regulations in California requiring a permit to conduct well stimulation), bans on hydraulic stimulation in certain locations, and/or 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.
We use water in our hydraulic stimulation operations. 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. 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 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. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Were the EPA to propose a rulemaking, the consent decree requires that EPA take final action by no later than July 15, 2021. 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.

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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. 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 December 2017, the Department of Interior issued a new opinion revoking its prior enforcement policy and concluded that an incidental take is not a violation of the Migratory Bird Treaty Act. Various environmental groups have filed lawsuits challenging this opinion. The ESA has not previously had a significant impact on our operations. Nevertheless, the designation of previously unprotected species 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.
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. In November 2017, the EPA published a list of areas that are in compliance with the new ozone standard, and separately, in December 2017, issued responses to state recommendations for designating non-attainment areas. In April 2018, the EPA issued final attainment status designations for most of the remaining portions of the United States.
State 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

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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.
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.
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. 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”). Currently, the Clean Water Rule and the scope of federal jurisdiction under the CWA are the subject of several legal challenges, and implementation of the rule has been blocked in some states. The EPA is also considering revising the scope of the 2015 rule, but any changes to the rule are likely to face judicial challenges from certain states and environmental groups. At this time we cannot predict how the original 2015 rule will be revised or whether it will be fully implemented as originally finalized. 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.

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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 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

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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.
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, 2018, 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 2019 or that will otherwise have a material impact on our financial position, results of operations or cash flows.
Employees
As of December 31, 2018, we had 322 employees.
Emergence from Chapter 11 Bankruptcy
On May 11, 2016, our predecessor company 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. Through the Chapter 11 Proceedings, the Company significantly improved its financial position from that of Berry LLC while it was owned by the Linn Entities. A final decree closing the Chapter 11 Proceedings were 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.

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Corporate Information
We were incorporated in Delaware in February 2017. We have executive offices located at 5201 Truxtun Ave., Bakersfield, California 93309 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.berrypetroleum.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.
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, our plans to return capital and other obligations and financial commitments.
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 heavily influence our revenue, profitability, access to capital, 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 during 2018 from $62.59 per Bbl at the beginning, to a high of $86.29 per Bbl and back to $50.47 per Bbl at the end of the year. The Henry Hub spot price for natural gas also fluctuated during 2018 between $2.55 per MMBtu and $3.23 per MMBtu and are currently higher in markets where we purchase gas. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:
worldwide and regional economic conditions impacting the global supply and demand for, and transportation costs of, oil and natural gas;
the price and quantity of foreign imports of oil;
prevailing prices on local price indexes in the areas in which we operate;
political and economic conditions in, or affecting, other producing regions or countries, including the Middle East, Africa, South America and Russia;
the level of global exploration, development and production, and resulting inventories;
actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;
actions of other significant producers;
the proximity, capacity, cost and availability of gathering and transportation facilities;
the cost of exploring for, developing, producing and transporting reserves;
weather conditions and natural disasters;
technological advances, conservation efforts and availability of alternative fuels affecting oil and gas consumption;

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refining and processing disruptions or bottlenecks;
the impact of U.S. dollar exchange rates on oil;
expectations about future oil and gas prices; and
Foreign and U.S. federal, state and local and non-U.S. governmental regulation and taxes, including the recent relaxation of U.S. export restrictions.
Lower oil prices may reduce our cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected.
Also, lower prices generally adversely affect the quantity of our reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. However, increased gas prices could negatively impact our oil reserves to the extent it made them more costly to extract. In addition, a portion of our PUDs may no longer meet the economic producibility criteria under the applicable rules or may be removed due to a lower amount of capital available to develop these projects within the SEC-mandated five-year limit.
In addition, sustained periods with oil and natural gas prices at levels lower than current prices also may adversely affect our drilling economics, which 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, which would reduce the net present value of our 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 make and expect to continue to make capital expenditures for the development and exploration of our oil and natural gas reserves. 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 regulatory, 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. We have a 2019 capital expenditure budget of approximately $195 million to $225 million. 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, 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. If we are able to obtain debt financing, it would require that a portion of our cash flows from operations be used to service such indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions. 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

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development of our properties, which in turn could lead to a decline in our reserves and production. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
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.
The development of our heavy oil in California is subject to our ability to generate sufficient quantities of steam using natural gas at an economically effective cost. As a result, we need access to natural gas at prices sufficiently lower than oil prices on an energy equivalent basis to economically produce our heavy oil. 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 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 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.
We may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations, and our commodity-price risk-management activities may prevent us from fully benefiting from price increases and may expose us to other risks.
As of December 31, 2018, we have hedged crude oil production at the following approximate volumes and prices: 17.5 MBbl/d at $70 per barrel in 2019, and 1.2 MBbl/d at $65 per barrel in 2020. In the future, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.
Our current commodity-price risk-management activities may prevent us from realizing the full benefits of price increases above the levels determined under the derivative instruments we use to manage price risk. In addition, our commodity-price risk-management activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including 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.
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. 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.

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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 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 pipeline safety agencies have adopted or proposed regulations to expand their jurisdiction to include more gas and liquid gathering lines and pipelines and to impose additional mechanical integrity requirements. The State of California has adopted additional regulations on the storage of natural gas that could affect the demand or availability of such storage, increase seasonal volatility, or otherwise affect the prices we pay for fuel gas.
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 increased fluid injection regulation and idle well decommissioning. In addition, we may experience delays, as we have in the past, due to 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.
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 and operating costs;
ad valorem, excise, and income taxes and costs related to GHG regulations;

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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. Reduced capital expenditures may result in a decline in our reserves. Our ability to make the necessary long-term capital expenditures or acquisitions needed to maintain or expand our reserves may be impaired to the extent cash flow from operations or external sources of capital are insufficient. We may not be successful in developing, exploring for or acquiring additional reserves. Over the long-term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development, production and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable or economically desirable oil and natural gas 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; and
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.
Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations as well as the uncertainties of drilling noted above. For a discussion of the uncertainty involved in these processes, see “—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.
Further, many additional factors may curtail, delay or cancel our scheduled drilling projects and ongoing operations, including the following:
delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on water disposal, emission of GHGs, steam injection and well stimulation;
pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for steam used in production or pressure maintenance;
lack of available gathering facilities or delays in construction of gathering facilities;
lack of available capacity on interconnecting transmission pipelines; and
other market limitations in our industry.
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. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. We make assumptions that may prove inaccurate about the consistency and accuracy of data when we identify these locations. 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 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 5% of our total net acreage at December 31, 2018.
Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation. In addition, 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, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to natural gas and oil exploration and development companies. Such legislative proposals have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. The future passage of any legislation as a result of these proposals or other changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development or otherwise significantly increase our costs.
Furthermore, in California, there have been, and currently are, proposals for new taxes on oil and natural gas production. 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 for acquisitions, 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. In California, where we have the most experience operating, we have few competitors. However, most are larger than us. Our competitors may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has historically continually increased due to competition and may increase substantially in the future.

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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 2019 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 variables 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, which could indirectly limit our ability to acquire assets and businesses. 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. Viable 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 24% of our steam capacity and approximately 63% 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. These facilities are dependent on viable contracts for the sale of electricity. 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. Furthermore, market fluctuations in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration facilities and any corresponding increase in the price of steam could significantly impact our operating costs. If we were unable to find new or replacement steam sources, lose existing sources or experience installation delays, we may be unable to maximize production from our heavy oil assets. If we were to lose our electricity sources, we would be subject to the electricity rates we could negotiate . For a more detailed discussion of our electricity sales contracts, see “Items 1 and 2. Business and Properties—Operational Overview—Electricity.”
Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.
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. These agreements contain covenants, that, among other things, limit our ability to:
incur or guarantee additional indebtedness;
make investments (including certain loans to others);
merge or consolidate with another entity;
make dividends and certain other payments in respect of our equity;
hedge future production or interest rates;
create liens that secure indebtedness or certain other obligations;
transfer, sell or otherwise dispose of assets;
repay or prepay certain indebtedness prior to the due date;
enter into transactions with affiliates; and
engage in certain other transactions without the prior consent of the lenders.

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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 borrowing base under the RBL Facility is subject to periodic redetermination.
The amount available to be borrowed under the RBL Facility is subject to a borrowing base and will be redetermined semiannually on or about each May 1 and November 1 and will depend on the volumes of our estimated proved oil and natural gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent of, or two-thirds of the lenders under, the RBL Facility. We, and 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 borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the facility and an acceleration of the loans outstanding under the facility, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results.
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.
If our cash flows and capital resources were insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness would depend on the condition of the capital markets and our financial condition at such time, including the view of the markets of our credit risk after recent defaults. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with new covenants that further restrict business operations and opportunities. 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.
Future 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.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. 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

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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 the year ended December 31, 2016, we recorded non-cash impairment charges of approximately $1.0 billion.
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, 2018, sales to Andeavor, Phillips 66 and Kern Oil & Refining accounted for approximately 35%, 28% and 13% respectively, of our sales.
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. This concentration of purchasers may impact our overall credit risk in that these entities 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 due to this significant customer concentration, if we were to lose any one of our major purchasers, the loss could cause us to cease or delay both production and sale of our oil and natural gas in the area supplying that purchaser.
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. Because of this geographic concentration, the success and profitability of our operations may be disproportionately influenced by conditions there. These conditions include local price fluctuations, changes in state or regional laws and regulations affecting our operations, political risks, limited acquisition opportunities where we have the most operating experience and infrastructure 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. For a discussion of regulatory risks, see “—Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including 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.” The concentration of our operations in California and limited local storage options also increase our exposure to events such as natural disasters, including wildfires, mechanical failures, industrial accidents or labor difficulties.
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, refinery shutdowns and turnarounds and the ability of such facilities 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. The amount of oil, gas and NGLs that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. If our access to markets for commodities we produce is restricted, our costs could increase and our expected production growth may be impaired.

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If our assets become subject to FERC regulation or federal, state or local regulations or policies change, or if we fail to comply with market behavior rules, our financial condition, results of operations and cash flows could be materially and adversely affected.
Our gathering and transportation operations are exempt from regulation by FERC, under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish that a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC- regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts, or Congress. If the FERC were to determine that one of our facilities or the services it provides were not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation, which could decrease revenue, increase operating costs and otherwise adversely affect our results of operations and cash flows. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. The FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations in excess of $1 million per day for each violation and disgorgement of profits associated with any violation.
Moreover, FERC regulations indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and market center promotion, indirectly affect the intrastate natural gas market.
In addition, State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale.
For more information regarding federal and state regulation of our operations, please see “Items 1 and 2. Business and Properties—Regulation of Health, Safety and Environmental Matters.”
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. The Dodd-Frank Act required the Commodity Futures Trading Commission to promulgate a range of 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.

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Concerns about climate change and other air quality issues may affect our operations or results.
Concerns about climate change and regulation of GHGs and other air quality issues may materially affect our business in many ways, including by increasing the costs to provide our products and services, and reducing demand for, and consumption of, the oil and gas we produce. We may be unable to recover or pass through all or any of these costs. In addition, legislative and regulatory responses to such issues may increase our operating costs and render certain wells or projects uneconomic. To the extent financial markets view climate change and GHG emissions as a financial risk, this could adversely impact our cost of, and access to, capital. Both California and the EPA have adopted laws and policies that seek to reduce GHG emissions as discussed in “Items 1 and 2. Business and Properties—Regulation of Health, Safety and Environmental Matters—Climate Change” and “—California GHG Regulations.” Compliance with California cap-and-trade program laws and regulations could significantly increase our capital, compliance and operating costs and could also reduce demand for the oil and natural gas we produce. The cost of acquiring GHG emissions allowances will depend on the market price for such instruments at the time they are purchased, the distribution of cost-free allowances among various industry sectors by the California Air Resources Board, and our ability to limit GHG emissions and implement cost-containment measures. In addition, on September 10, 2018, the Governor of California signed into law a bill that would commit California to the use of 100% zero-carbon electricity by 2045. The same day, the Governor also signed an executive order committing California to total economy-wide carbon neutrality by 2045. While the law does not directly affect the oil and gas industry, and it remains unclear what actions state agencies may take in response to the executive order, these recent actions could result in decreased future demand for the oil and gas we produce and in turn have an adverse effect on our business and results of operations.
In addition, other current and proposed international agreements and federal and state laws, regulations and policies seek to restrict or reduce the use of petroleum products in transportation fuels and electricity generation, impose additional taxes and costs on producers and consumers of petroleum products, and require or subsidize the use of renewable energy. For example, the International Maritime Organization has imposed global sulfur caps on ships sailing in emissions control areas, which are set to take effect by January 2020, and may decrease demand, or the prices we can obtain, for our products.
Governmental authorities can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act (the “CAA”) and associated state laws and regulations. For example, the San Joaquin Valley will be required to adopt more rigorous attainment plans under the CAA to comply with federal ozone and particulate matter standards, and these efforts could affect our activities in the region. In addition, California air quality laws and regulations, particularly in southern and central California where most of our operations are located, are in most instances more stringent than analogous federal laws and regulations.
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, including well drilling, completion, stimulation, maintenance, water disposal, marketing and transportation and abandonment activities, are subject to operational 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, 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. 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

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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. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected.
We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Risks Related to Emergence
Our financial condition or results of operations are not comparable to the financial condition or results of operations reflected in our historical financial statements.
Since February 28, 2017, we have been operating under a new capital structure. In addition, we adopted fresh-start accounting and, as a result, at February 28, 2017 our assets and liabilities were recorded at fair value, which resulted in values that are materially different than the values that were recorded in our historical financial statements. Accordingly, our financial condition and results of operations from and after the Effective Date are not comparable to the financial condition or results of operations reflected in our historical financial statements. Further, as a result of the implementation of the Plan and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.
Due to our limited operating history as an independent company following our emergence from bankruptcy in February 2017, we have been in the process of establishing our accounting and other management systems and resources. We may be unable to effectively complete the development of a mature system of internal controls, and a failure of our control systems to prevent error or fraud may materially harm our company.
Our predecessor company was an indirect, wholly owned subsidiary of Linn Energy, and we utilized Linn Energy’s systems, software and personnel to prepare our financial information and to ensure that adequate internal controls over financial reporting were in place. Following our emergence from bankruptcy in February 2017, we assumed responsibility for these functions. In the course of transitioning these functions, we put in place a new executive management team and continue to add personnel, upgrade our systems, including information technology, and implement additional financial and managerial controls, reporting systems and procedures. These activities place

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significant demands on our management, administrative and operational resources, including accounting resources, and involve risks relating to our failure to manage this transition adequately.
Proper systems of internal controls over financial accounting and disclosure controls and procedures are critical to our business. If we are unable to effectively complete the development of a mature system of internal controls, we may be unable to continue reliably assimilating and compiling financial information about our company, which would significantly impair our ability to prevent error, detect fraud or access capital markets.
A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Failure of our control systems to prevent error or fraud could materially adversely impact us.
Our limited operating history makes it difficult to evaluate our business plan and our long-term viability cannot be assured.
Our prospects for financial success are difficult to assess because we have a limited operating history since emergence from bankruptcy. There can be no assurance that our business will be successful, that we will be able to maintain a profitable operation, or that we will not encounter unforeseen difficulties that may deplete our capital resources more rapidly than anticipated. There can be no assurance that we will sustain profitability or positive cash flows from our operating activities.
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 Amended and Restated Certificate of Incorporation of Berry Corp. (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.

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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. In addition, our stockholders and their affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. Our business and prospects could be adversely affected if attractive business opportunities are procured by our stockholders for their own benefit rather than for ours.
Certain of our stockholders and their affiliates have resources greater than ours, which may make it more difficult for us to compete with such persons with respect to commercial activities as well as for potential acquisitions. As a result, competition from certain stockholders and their affiliates could adversely impact our results of operations.
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.
We may sell or otherwise issue additional shares of common stock or securities convertible into shares of our common stock. The Certificate of Incorporation provides that Berry Corp.’s authorized capital stock consists of 750,000,000 shares of common stock and 250,000,000 shares of preferred stock. In addition, we registered shares of the great majority of our common stock for resale and conditions limiting such resales expired January 21, 2019. The holders of those shares largely comprised creditors of Berry LLC prior to its bankruptcy and we cannot predict when or whether they will sell such shares. Such sales, or concerns about them, may put downward pressure on the market price of our common stock.
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 Berry Petroleum Corporation 2017 Omnibus Incentive Plan, as amended and restated (our Restated Incentive 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 Restated Incentive 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 Restated Incentive Plan 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 the common stock.

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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 “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.
“Emerging growth companies” can also delay adopting new or revised accounting standards until such time as those standards apply to private companies. 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 under Section 107 of the JOBS Act until we are no longer 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 pursuant to Section 107 of the JOBS Act.
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.
We will incur significant costs and devote substantial management time as a result of operating as a public company, particularly after we are no longer an “emerging growth company.”
Our management and other personnel are required to divert attention from operational and other business matters to devote substantial time to public company requirements. After we no longer qualify as an “emerging growth company,” we expect to incur additional management time and cost to comply with the more stringent reporting requirements applicable to companies that are deemed accelerated filers or large accelerated filers, including complying with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act. We currently do not have an internal audit function, and we have needed, and will continue to need, to hire or contract for additional accounting and financial staff with appropriate public company experience and technical accounting knowledge.
If we do not adequately develop or maintain all required financial reporting and disclosure procedures and controls, we may be unable to provide the financial information required of a U.S. publicly traded company in a timely and reliable manner.
As a private company we were not required to adopt or maintain all of the financial reporting and disclosure procedures and controls required of a U.S. publicly traded company. If we fail to adequately develop and maintain effective internal controls and procedures and disclosure procedures and controls, we may be unable to provide the financial information and SEC reports that a U.S. publicly traded company is required to provide in a timely and reliable fashion. Any such delays or deficiencies could penalize us, including by limiting our ability to obtain financing, either in the public capital markets or from private sources and hurt our reputation and could thereby impede our ability to implement our growth strategy.
Our internal control over financial reporting is not currently required to meet the standards required by Section 404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial reporting

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in accordance with Section 404 of the Sarbanes-Oxley Act in the future could have a material adverse effect on our business and share price.
Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal control over financial reporting, starting with the second annual report that we file with the SEC after the consummation of the IPO, and generally requires a report by our independent registered public accounting firm on the effectiveness of our internal control over financial reporting. However, under the JOBS Act, 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, prevent fraud and operate successfully as a public company. 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.
In connection with the implementation of the necessary procedures and practices related to internal control over financial reporting, we may identify deficiencies that we may not be able to timely remediate. In addition, we may encounter problems or delays in completing the implementation of any remediation of control deficiencies and receiving a favorable attestation in connection with the attestation provided by our independent registered public accounting firm. 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 the Certificate of Incorporation and Bylaws, as well as our stockholders agreement, 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 the Form of the Second Amended and Restated Bylaws of Berry Corp. (the “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 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. Additionally, we and many of the largest holders of our equity securities are bound by a stockholders agreement that requires us to nominate for election and take all other necessary actions to cause an individual designated by Benefit Street Partners to be included in the slate of nominees recommended by the board of directors to be elected to the board of directors.
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.
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

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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. Any person or entity purchasing or otherwise acquiring any interest in shares of our common stock will be deemed to have notice of, and consented to, the provisions of our Certificate of Incorporation described in the preceding sentence. 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.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
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—Lawsuits, Claims, 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 began trading on the NASDAQ under the ticker symbol “BRY” on July 26, 2018. Prior to that, there was no public market for our common stock.
Holders of Record  
Our common stock was held by 102 stockholders of record at January 31, 2019, and by approximately 2,100 additional stockholders whose shares were held for them in street name or nominee accounts.
Dividend Policy
We plan to use our operating cash flows to cover our interest requirements, fund our maintenance capital requirements, 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 the Second Amended and Restated Berry Petroleum Corporation 2017 Omnibus Incentive Plan (the “Omnibus Plan”). A description of the plans can be found in Item 8. Financial Statements and Supplementary Data – Note 8–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 approximately 1.6 million have been issued or reserved through December 31, 2018.
The following table summarizes information related to our equity compensation plans under which our equity securities are authorized for issuance as of December 31, 2018.
Plan Category

Number of Securities to be Issued Upon Exercise of Outstanding Options and Rights (#)(3)

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

Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
(#)
(1)
Equity compensation plans not approved by security holders(2)

922,952

N/A

8,381,902
________________
(1)  
The number of securities remaining available for future issuances has been reduced by the number of securities to be issued upon RSUs subject to time vesting and PSUs upon the 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)  
Represents common stock to be issued based upon continuous employment and the maximum achievement of certain performance goals over a specified period of time as described in the applicable Equity Compensation Plan and associated award agreements. We did not have any options or rights with an exercise price.   


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Sales of Unregistered Securities
Between January 1, 2018 and August 3, 2018, we issued 895,422 RSUs and 754,539 PSUs to certain of our employees and directors in connection with services provided to us, which issuances were not registered under the Securities Act of 1933, as amended (the “Securities Act”). In connection with our IPO, on August 3, 2018, we filed a Registration Statement on Form S-8 registering future issuances of common stock underlying our RSUs and PSUs.
The offers, sales and issuances of the securities described in the preceding paragraph were deemed to be exempt from registration either under Rule 701 promulgated under the Securities Act in that the transactions were under compensatory benefit plans and contracts relating to compensation, or under Section 4(a)(2) of the Securities Act in that the transactions were between an issuer and members of its senior executive management and did not involve any public offering within the meaning of Section 4(a)(2).
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.
On February 8, 2018, we completed the 2026 Notes offering. The 2026 Notes were issued at a price of 100% of par, and the sale resulted in net proceeds (after deducting the initial purchasers’ discounts and commissions and estimated offering expenses and excluding accrued interest) to the Company of approximately $391 million. We used the net proceeds to repay borrowings under our RBL Facility and for general corporate purposes.
The 2026 Notes were issued and sold to the initial purchasers in a private placement exempt from the registration requirements of the Securities Act. The initial purchasers sold the 2026 Notes to qualified institutional buyers inside the United States in reliance on Rule 144A of the Securities Act and to persons outside the United States under Regulation S of the Securities Act.
Stock Repurchase Program
On December 13, 2018, our Board of Directors announced it had adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of current market conditions for our common stock they authorized current repurchases of up to $50 million under the program. 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 Petroleum to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. In December 2018, we repurchased 448,661 shares at an average price of $8.81 per share. The Company repurchased 1,932,096 shares from January 1, 2019 through February 28, 2019, resulting in a total of 2,380,757 shares repurchased under the Stock Repurchase Program as of February 28, 2019.
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
December 1 - 31, 2018
 
448,661

 
$
8.81

 
448,661

 
$
46,047,000






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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 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.
COMPARISON OF 6 MONTH CUMULATIVE TOTAL RETURN(1)(2) 
Among Berry Petroleum Corporation, the S&P Smallcap 600 Index,
the Dow Jones U.S. Exploration & Production Index
and the Vanguard Energy ETF
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12766478&doc=22
 
 
07/26/18
 
07/18
 
08/18
 
09/18
 
10/18
 
11/18
 
12/18
 
01/19
Berry Petroleum Corporation
 
$
100.00

 
$
103.77

 
$
123.70

 
$
133.73

 
$
106.25

 
$
94.04

 
$
67.17

 
$
90.51

S&P Smallcap 600
 
$
100.00

 
$
103.16

 
$
108.15

 
$
104.71

 
$
93.74

 
$
95.15

 
$
83.66

 
$
92.56

Dow Jones U.S. Exploration & Production
 
$
100.00

 
$
103.39

 
$
100.56

 
$
102.81

 
$
88.00

 
$
82.46

 
$
71.18

 
$
80.76

Vanguard Energy ETF
 
$
100.00

 
$
100.06

 
$
97.10

 
$
99.64

 
$
87.58

 
$
85.09

 
$
73.67

 
$
82.30

__________
(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 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, 2016 and as of and for the two months ended February 28, 2017 is derived from the audited historical financial statements of our predecessor company. The selected historical financial information as of and for the ten months ended December 31, 2017 and as of and for the year ended December 31, 2018 is derived from audited consolidated financial statements of the successor company.
Upon Berry LLC’s emergence from bankruptcy on February 28, 2017, or the Effective Date, in connection with the Plan, 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. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. These fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our predecessor company’s historical balance sheet. The effects of the Plan and the application of fresh-start accounting are reflected in Berry Corp.’s consolidated financial statements as of the Effective Date and the related adjustments thereto are recorded in our consolidated statements of operations as reorganization items for the periods prior to the Effective Date. 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. You should read the following table in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical financial statements of our predecessor and accompanying notes included elsewhere in this report.

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Berry Corp. (Successor)
 
 
Berry LLC (Predecessor)
 
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
$
586,557

 
$
319,669

 
 
$
92,718

 
$
410,991

Net income (loss)
$
147,102

 
$
(21,068
)
 
 
$
(502,964
)
 
$
(1,283,196
)
Net income (loss) attributable to common stockholders
$
49,160

 
$
(39,316
)
 
 
n/a

 
n/a

Net income (loss) per share of common stock
 
 
 
 
 
 
 
 
Basic
$
0.85

 
$
(1.02
)
 
 
n/a

 
n/a

Diluted
$
0.85

 
$
(1.02
)
 
 
n/a

 
n/a

Dividends per common share
$
0.21

 
$

 
 
$

 
$

Weighted-average common stock outstanding
 
 
 
 
 
 
 
 
Basic
57,743

 
38,644

 
 
n/a

 
n/a

Diluted(1)
57,932

 
38,644

 
 
n/a

 
n/a

Cash Flow Data:
 
 
 
 
 
 
 
 
Operating activities(2)
$
103,100

 
$
107,399

 
 
$
22,431

 
$
13,197