Document
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
þ    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from         to
Commission File Number 001-36478

California Resources Corporation
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
 
46-5670947
(I.R.S. Employer
Identification No.)
 
 
 
9200 Oakdale Ave.
Los Angeles, California
(Address of principal executive offices)
 
91311
(Zip Code)
(888) 848-4754
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock
 
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
Yes¨   No  þ
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 þ   No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period as the registrant was required to submit and post files).      Yes þ   No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
¨
Accelerated Filer
þ
Non-Accelerated Filer
¨
Smaller Reporting Company
¨
Emerging Growth Company
¨
 
 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yes ¨   No  þ
The aggregate market value of the voting common stock held by nonaffiliates of the registrant was approximately $363 million, computed by reference to the closing price on the New York Stock Exchange composite tape of $8.55 per share of Common Stock on June 30, 2017. Shares of Common Stock held by each executive officer and director have been excluded from this computation in that such persons may be deemed to be affiliates. This determination of potential affiliate status is not a conclusive determination for other purposes.
At January 31, 2018, there were 42,901,946 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement to be filed with the Securities and Exchange Commission in connection with the registrant's 2018 Annual Meeting of Stockholders, are incorporated by reference into Part III of this Form 10-K.

1



TABLE OF CONTENTS
 
  Page
Part I
 
 
Item 1
BUSINESS
 
General
 
Business Operations and Environment
 
Our Business Strategy
 
Key Characteristics of our Operations
 
Portfolio Management and Capital Program
 
Reserves and Production Information
 
Marketing Arrangements
 
Regulation of the Oil and Natural Gas Industry
 
Employees
 
Spin-Off and Reverse Stock Split
 
Available Information
Item 1A
RISK FACTORS
Item 1B
UNRESOLVED STAFF COMMENTS
Item 2
PROPERTIES
 
Our Operations
 
Exploration Program
 
Our Reserves
 
Drilling Locations
 
Production, Price and Cost History
 
Productive Wells
 
Acreage
 
Drilling Activities
 
Delivery Commitments
 
Our Infrastructure
Item 3
LEGAL PROCEEDINGS
Item 4
MINE SAFETY DISCLOSURES
 
EXECUTIVE OFFICERS
Part II
 
 
Item 5
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Item 6
SELECTED FINANCIAL DATA
Item 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Basis of Presentation and Certain Factors Affecting Comparability
 
Business Environment and Industry Outlook
 
Seasonality
 
Joint Ventures
 
Private Placement
 
Acquisitions and Divestitures
 
Income Taxes
 
Operations
 
Production and Prices
 
Balance Sheet Analysis
 
Statement of Operations Analysis
 
Liquidity and Capital Resources
 
Cash Flow Analysis
 
2017 and 2018 Capital Program
 
Off-Balance-Sheet Arrangements
 
Lawsuits, Claims, Commitments and Contingencies
 
Critical Accounting Policies and Estimates
 
Significant Accounting and Disclosure Changes
Item 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

2



 
FORWARD-LOOKING STATEMENTS
Item 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Report of Independent Registered Public Accounting Firm
 
Consolidated Balance Sheets
 
Consolidated Statements of Operations
 
Consolidated Statements of Comprehensive Income
 
Consolidated Statements of Equity
 
Consolidated Statements of Cash Flows
 
Notes to Consolidated Financial Statements
 
Quarterly Financial Data (Unaudited)
 
Supplemental Oil and Gas Information (Unaudited)
 
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Item 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Item 9A
CONTROLS AND PROCEDURES
Item 9B
OTHER INFORMATION
Part III
 
 
Item 10
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 11
EXECUTIVE COMPENSATION
Item 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Item 13
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Item 14
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Part IV
 
 
Item 15
EXHIBITS


3



PART I

Item 1
BUSINESS

General

We are an independent oil and natural gas exploration and production company operating properties within California. We are the largest oil and gas producer in California on a gross operated basis and we believe we have the largest privately held mineral acreage position in the state, consisting of approximately 2.3 million net mineral acres spanning the state’s four major oil and gas basins. We produced approximately 129 thousand barrels of oil equivalent per day (MBoe/d) for the year ended December 31, 2017. As of December 31, 2017, we had net proved reserves of 618 million barrels of oil equivalent (MMBoe), of which approximately 71% was categorized as proved developed reserves. Oil represented 72% of our proved reserves. We were formed in April 2014 and listed on the New York Stock Exchange on December 1, 2014. All references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.
Business Operations and Environment

Our business is focused on the production, development and exploration of conventional and unconventional oil and gas assets in California.
Our large acreage position and extensive drilling inventory provide us a diversified portfolio of oil and natural gas locations that are economically viable in a variety of operating and commodity price conditions, including many that are high-value projects throughout the price cycle. Our large fee mineral acreage position also enhances our returns because we do not make royalty and other lease payments related to these assets. Our acreage position contains numerous development and growth opportunities due to its varied geologic characteristics and multiple stacked pay reservoirs which are in many cases thousands of feet thick. We have a large portfolio of low-risk and low-decline conventional opportunities in each of our major oil and gas basins comprising approximately 71% of our proved reserves. Conventional reservoirs are capable of natural flow during primary recovery phase, often followed by waterflood and steamflood recovery methods to enhance ultimate recovery. We also have a significant portfolio of lower permeability unconventional reservoirs that typically utilize established well stimulation techniques. Our conventional and unconventional reservoirs currently include approximately 20,550 and 4,530 net identified drilling locations, respectively, primarily in the San Joaquin basin.

We are in various phases of developing many of our conventional assets and will continue to develop them using internally generated cash flow and, when appropriate, capital raised through joint ventures. Prior to the severe price declines that began in late 2014, we were focused on higher-value unconventional production from seven discrete stacked pay horizons within the Monterey formation, primarily within the upper Monterey. As commodity prices and project economics improved in 2017, we renewed our development activities in the upper Monterey and started to appraise and delineate the Kreyenhagen formation within our Kettleman North Dome field. We expect to continue pursuing unconventional opportunities in 2018 and beyond if prices remain at current levels. Over the longer term, we believe our project economics will improve, which should allow us to duplicate our successful upper Monterey results to develop opportunities in the unconventional reservoirs of the lower Monterey, Kreyenhagen and Moreno formations, which have similar geological attributes.

We have also built a 3D seismic library that covers approximately 4,820 square miles, representing over 90% of the 3D seismic data available in California. We have developed unique, proprietary stratigraphic and structural models of the subsurface geology and hydrocarbon potential in each of the four basins in which we operate. In recent years we have tested and successfully implemented various exploration, drilling, completion and enhanced recovery technologies to increase recoveries, growth and value from our portfolio. We continue working to build depth in our exploration inventory and identify new prospects based on the competitive advantage provided by this proprietary data set and our experience.

4



We develop our capital program by prioritizing life-of-project returns to grow our net asset value over the long term, while balancing the short- and long-term growth potential of each of our assets. We use a Value Creation Index (VCI) metric for project selection and capital allocation across our asset portfolio. We calculate the VCI for each of our projects by dividing the net present value of the project's expected pre-tax cash flow over its life by the present value of the investments, each using a 10% discount rate. Projects are expected to meet a VCI of 1.3, meaning that 30% of expected value is created above our cost of capital for every dollar invested. Our technical teams are consistently working to enhance value by improving the economics of our inventory through detailed geologic studies as well as application of more effective and efficient drilling and completion techniques. As a result, we expect many projects that do not currently meet our VCI threshold today will do so by the time of development. We regularly monitor internal performance and external factors and adjust our capital investment program with the objective of creating the most value from our asset portfolio.
With significant operating control of our properties, we have the ability to adjust our drilling and workover rig count based on commodity prices and to increase or decrease our program according to changing market conditions. We began 2017 with two drilling rigs and ended the year with nine; seven in the San Joaquin basin and one each in the Los Angeles and Ventura basins. We drilled and completed 109 net development wells with 92 wells in the San Joaquin basin, 15 in the Los Angeles basin and two in the Ventura basin. These included six primary wells, 52 steamflood wells, 31 waterflood wells, and 20 unconventional wells. We also drilled and completed five net exploration wells in the San Joaquin basin. In 2017, we increased our workover rig count from 43 at the beginning of 2017 to 59 at the end of the year to focus on projects that meet our investment criteria. In total, we performed approximately 460 capital workover projects during 2017.
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
The following table summarizes certain information concerning our acreage, wells and drilling locations as of December 31, 2017:
 
Mineral Acreage(a) 
(in millions)
 
Average Net Mineral Acreage Held in Fee (%)
 
Producing Wells, gross
 
Average Net Revenue Interest
 (%)
 
Identified Drilling Locations(b)
 
Gross
 
Net
 
 
 
 
Gross
 
Net
San Joaquin Basin
1.7

 
1.5

 
66
%
 
6,192

 
79
%
 
25,190

 
17,530

Los Angeles Basin
<0.1

 
<0.1

 
46
%
 
1,300

 
76
%
 
1,950

 
1,930

Ventura Basin
0.3

 
0.2

 
73
%
 
467

 
82
%
 
4,310

 
3,900

Sacramento Basin
0.6

 
0.5

 
38
%
 
677

 
75
%
 
2,420

 
1,720

Total
2.7

 
2.3

 
60
%
 
8,636

 
78
%
 
33,870

 
25,080

(a)
We currently hold approximately 38,500 gross (30,300 net) acres in the Los Angeles basin. Our Los Angeles basin operations primarily rely on dense multi-well pad drilling.
(b)
Our total identified drilling locations exclude approximately 6,400 gross (5,300 net) exploration drilling locations related to unconventional reservoirs. They include approximately 2,090 gross (1,870 net) locations associated with proved undeveloped reserves and approximately 2,520 gross (2,350 net) injection well locations. Please see Item 2 – Properties – Drilling Locations for more information regarding the processes and criteria through which we identified our drilling locations.

Compared to 2016, our 2017 production declined 8%, with only $266 million of drilling and workover capital invested for the year. This performance reflects the resilience of our asset base and the further flattening of our base production decline. In 2017, our production profile comprised roughly 64% oil, 24% natural gas and 12% natural gas liquids. Recognizing the relative value of crude oil, we are devoting the majority of our 2018 capital program to grow our oil production.
We have created a dynamic capital program for 2018 that can be adjusted to align investments with projected cash flows and joint venture (JV) funding. We believe our expanded 2018 capital program focusing primarily on low-decline crude oil assets will provide meaningful deleveraging over time while we continue to pursue additional opportunities to strengthen our balance sheet. Our capital program will also allow us to continue to delineate our high-potential conventional and unconventional areas like Buena Vista Nose and Kettleman, respectively.


5



We currently sell all of our crude oil into the California refining markets, which offer favorable pricing for comparable grades relative to other U.S. regions. Although California state policies actively promote and subsidize renewable energy, including solar, wind, biomass and geothermal resources, demand for oil and natural gas in California remains strong. California is heavily reliant on imported sources of energy, with approximately 72% of oil and 90% of natural gas consumed in 2017 imported from outside the state. A vast majority of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices. We believe that the limited crude transportation infrastructure from other parts of the U.S. and California refiners' preference to run on heavy grades of oil found in California will continue contributing to favorable prices and realizations compared to other U.S. markets. During the second half of 2017, Brent crude prices began to recover, rising above $65 per barrel and reaching the highest level since 2015 as the premium of Brent over West Texas Intermediate (WTI) widened with the Organization of the Petroleum Exporting Countries (OPEC) production cuts. Additionally, our differentials improved against Brent during 2017 as a result of an increase in the official selling price to North America from the Middle East and higher-than-expected demand in Asia.
During 2017, as oil prices and activity increased, the energy industry in certain parts of the country started experiencing increases in service costs. However, the California energy industry experienced only limited cost inflation due to excess capacity in the service and supply sector. At current commodity price levels, we expect this trend to continue in 2018.
Recent Developments
In February 2018, we entered into a midstream JV with ECR Corporate Holdings L.P. (ECR), a portfolio company of Ares Management L.P. (Ares). This JV (Ares JV) holds the Elk Hills’ power plant, a 550 MW natural gas fired power plant, and a 200 million cubic foot per day cryogenic gas processing plant. For more on the Ares JV, see Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Joint Ventures.

Our Business Strategy

We plan to drive long-term stockholder value by applying modern technologies to develop our resource base and increase production. We have significant conventional opportunities to pursue, which we develop through their life cycles to increase recovery factors by transitioning them from primary production to waterfloods, steamfloods and other enhanced recovery mechanisms.

In a sustained higher price environment, we intend to direct additional available capital to projects that provide high-value returns. A higher sustained price environment also gives us the opportunity to acquire assets that would be complementary to our existing operations. The principal elements of our business strategy include the following:

Focus on high-value projects.
In the near term, we anticipate directing the majority of our capital investments toward oil-weighted opportunities to the extent the oil-to-gas price relationship remains favorable. As a result, we expect the percentage of our oil production to continue to increase over time and favorably impact our overall margins. In 2018, approximately 95% of our identified drilling inventory is associated with oil projects. Currently, 64% of our production is oil compared to 72% of our proved reserves. Over time, we expect our share of oil production to approach the share of oil reserves.

Over the longer term, we believe we can generate significant production growth from unconventional reservoirs such as tight sandstones and shales. We hold mineral interests in approximately 1.3 million net mineral acres with unconventional potential and have identified approximately 4,930 gross (4,530 net) drilling locations on this acreage. A meaningful portion of our production already comes from unconventional assets. While we have not yet developed sufficient information to reliably predict success rates across our entire portfolio, our continued technical reviews of these projects are allowing us to better understand performance of these reservoirs in addition to improving our overall cycle time from project identification to development. As a result, we believe we will be able to direct future available capital more precisely to higher value projects, allowing us to strategically increase our investment levels in unconventional drilling over time.


6



Maintain an appropriate share of conventional projects in our production mix to manage production declines and base maintenance capital requirements.
Our portfolio of assets includes a large number of steamflood and waterflood projects that have much lower decline rates than many unconventional projects. We intend to focus a significant portion of our capital investments on such projects, which we expect will maintain our low production decline rates. We have approximately 28,940 gross (20,550 net) identified drilling locations associated with lower-risk conventional opportunities, 56% of which are Improved Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) projects. The remaining 44% are associated with primary recovery methods, many of which we expect will develop into IOR and EOR projects in the future.

Enhance stockholder value by pursuing upstream and midstream joint venture opportunities including exploration ventures.
We believe both upstream and midstream joint ventures will enhance value by giving us the ability to significantly accelerate the development of our high-value portfolio of assets. We have already announced a number of joint ventures that have given us substantial development resources and will continue to evaluate similar opportunities in the future. We have entered into a number of exploration joint ventures, which, if successful, could result in significant long-term production growth.

Increase natural gas production over time to provide clean energy to California.
We are the largest producer of natural gas in California through our operations in the Sacramento basin. Our portfolio has a large number of mature gas fields that can be targeted for further development, with growth opportunities in under-developed areas of our asset base, including significant growth potential in the Sacramento basin. We are focused on developing technologies and execution approaches that will generate commercial projects at current price levels while maintaining a targeted exploration program for new resources. In addition, we expect to pursue strategic joint ventures to unlock the value of our asset portfolio.

Maintain a proactive and collaborative approach to safety, environmental protection and community outreach, while helping the state address its energy and water needs.
We are committed to managing our assets in a manner that safeguards people and protects the environment, and to reducing California's dependence on imported energy. We proactively engage with regulatory agencies, communities, organized labor and other stakeholders to pursue mutually beneficial outcomes that supply affordable and reliable energy from local sources and that expand opportunities for the communities in which we live and work. As a California company, helping our state meet its water needs is a key priority. We are a net water supplier to agriculture due to our dedicated team and investments in water conservation and the recycling of produced water from oil and gas reservoirs. In 2017, our operations supplied 4.9 billion gallons of reclaimed water for agricultural use, a new company record that far exceeds the volume of fresh water we purchased for our operations statewide.

Apply proven modern development and production methods to enhance production growth and cost efficiency.
Over the last several decades, the oil and gas industry has focused significantly less effort on utilizing modern development and exploration processes and technologies in California relative to other prolific U.S. basins. We believe this is largely due to other oil companies’ limited capital investments in California, concentration on shallow-zone thermal projects and investments in other assets within their global portfolios. As an independent company focused on California, we use proven modern technologies in drilling and completing wells, as well as production methods that we expect will substantially increase both our production and cost efficiency over time. We have developed an extensive 3D seismic library covering almost 4,820 square miles in all four of our basins, representing over 90% of the 3D seismic data available for California, and have tested and successfully implemented various exploration, drilling, completion, IOR and EOR technologies in the state.

Utilize advanced technologies to improve our operations.
We have a dedicated Big Data Analytics team focused on analyzing data to help us make better operating and development decisions that enhance the value of our assets. We are evaluating advanced technologies such as artificial intelligence, machine learning, algorithms, complex math analysis and other digital solutions to predictively optimize our business processes, development criteria and our drilling and production techniques.


7



Key Characteristics of our Operations

The following are among the key characteristics of our operations:
Operational control of our diverse asset base provides flexibility during commodity price cycles and preserves future value and growth potential.
Our near 100% operational control of 135 fields in California provides us flexibility to adapt our investments to various market environments through our ability to select drilling locations, the timing of our development and the drilling and completion techniques we use. Our large and diverse mineral acreage position allows us to choose to develop conventional or unconventional reservoirs of either oil or natural gas using multiple recovery mechanisms, such as primary, steamflood and waterflood. In addition, approximately 60% of our acreage position is held in fee and 15% is held by production, which gives us flexibility to choose the timing of our development projects. A majority of our interests are in producing properties located in reservoirs characterized by what we believe have long-lived production profiles with repeatable development opportunities. Approximately 95% of our identified drilling inventory is associated with oil-rich projects, primarily located in the San Joaquin, Los Angeles and Ventura basins, and the remaining inventory is associated with natural gas properties in the Sacramento, San Joaquin and Ventura basins. The variety of recovery mechanisms and product types available to us, together with our operating control, allows us to allocate capital in a manner designed to optimize cash flow over a wide range of commodity prices. The low base decline of our conventional assets allows us to limit production declines with minimal investment, positioning us to achieve oil-production growth in the current price environment while living within our means.

Largest acreage position in a world-class oil and natural gas province.
We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net mineral acres. California is one of the most prolific oil and natural gas producing regions in the world. California is also the nation’s largest state economy, and the world's sixth largest, with significant energy demands that exceed local supply. Our large acreage position with a diverse development portfolio enables us to pursue the appropriate production strategy for the relevant commodity price environment without the need to acquire new acreage. For example, in a high natural gas price environment we can rapidly increase our investments in the Sacramento basin to generate significant production growth. Our large acreage position also allows us to quickly deploy the knowledge we gain in our existing operations, together with our seismic data, in other areas within our portfolio.

Opportunity rich drilling and workover portfolio.
Our drilling inventory at December 31, 2017 consisted of approximately 33,870 gross (25,080 net) identified well locations, including approximately 28,940 gross (20,550 net) conventional drilling locations and approximately 4,930 gross (4,530 net) unconventional drilling locations. Our drilling inventory count increased by about 10% from the prior year as a result of our technical teams' continued efforts. We also have approximately 1,200 workover projects that can deliver high returns. At about $65 Brent, we estimate we have increased the investment opportunities for drilling and workover capital that meet our 1.3 VCI threshold by 20%. In the process, our inventory of lower-risk conventional development opportunities with attractive returns has increased even more than our unconventional opportunities. In a sustained favorable oil and gas price environment, we believe we can also achieve further long-term production growth through the development of unconventional reservoirs. In addition, our rich conventional and unconventional portfolio can provide attractive JV opportunities.

Proven operational management and technical teams with extensive experience operating in California.
The members of our operational management and technical teams have an average of over 25 years of experience in the oil and natural gas industry, with an average of over 15 years focused on our California oil and gas operations through different price cycles. Our teams have a proven track record of applying modern technologies and operating methods to develop our assets and improve their operating efficiencies. For example, we have successfully reduced field operating costs by approximately 27% since 2014.

8



Portfolio Management and Capital Program
We develop our capital program by prioritizing projects that have returns that will grow our net asset value over the long term, while balancing the short- and long-term growth potential of each of our assets. We use the VCI metric for project selection and capital allocation across our asset portfolio. Typically, we create the highest value by reinvesting our cash flow back into our business, including attractive acquisitions. Our low decline rates compared to our industry peers together with our high level of operational control give us the flexibility to adjust the level of such capital investments as circumstances warrant.

2017 Capital Program

Our 2017 capital program predominantly targeted projects in the San Joaquin and Los Angeles basins, and virtually all of our capital was directed towards oil-weighted production, consistent with 2016 and 2015. The program was initially set at approximately $300 million but increased to $371 million when we entered into JVs with Benefit Street Partners (BSP) and Macquarie Infrastructure and Real Assets Inc. (MIRA). Our $371 million capital program included $96 million of funding from BSP and excluded $58 million of funding from MIRA, which is not reported in our consolidated results. Excluding MIRA capital, we invested approximately $177 million for drilling wells, $89 million for capital workovers, $71 million for facilities and compression expansion, $25 million for maintenance and occupational health, safety and environmental projects and $9 million for exploration and other items. We ended 2017 with nine rigs running and anticipate our activity levels to remain at an average nine-rig pace for the first quarter of 2018.

2018 Capital Program

We are focusing our 2018 capital on oil projects, which provide higher margins and low decline rates that we believe will generate cash flow to fund increasing capital budgets that will grow production. Our approach to our 2018 drilling program is consistent with our stated strategy to remain financially disciplined and fund projects through either internally generated cash flow or JV capital to maintain our liquidity and further strengthen our balance sheet. We continue to deploy our partners' capital as part of our BSP and MIRA joint ventures and opportunistically pursue additional strategic relationships. We will deploy capital to projects that help continue to stabilize our production, develop our long-term resources and return our production to a growth profile. We will continue to focus on our core fields: Elk Hills, Wilmington, Kern Front and the delineation and appraisal of Kettleman North Dome and Buena Vista. We will also restart our development activities in the Huntington Beach field.

With stronger expected cash flow, we estimate our 2018 capital program will range from $425 million to $450 million, which includes approximately $100 to $150 million in JV capital. Our 2018 capital program may grow further through additional tranches from existing JVs as well as potential new JVs.

Our current drilling inventory comprises a diversified portfolio of oil and natural gas locations that are economically viable in a variety of operating and commodity price conditions. Our 2018 drilling program includes development of conventional and unconventional resources. The depth of our primary conventional wells is expected to range from 2,000 to 15,000 feet. With a significant reduction in our drilling costs since 2014, many of our deep conventional and unconventional wells have become more competitive, and we expect to use approximately 60% of our capital on drilling. We expect to focus our conventional program of approximately 130 wells primarily in Wilmington, Huntington Beach, Kern Front, Pleito Ranch and Mount Poso, which will largely consist of waterfloods and steamfloods along with some primary drilling. We intend to drill approximately 20 unconventional wells in the Buena Vista and Kettleman areas.

We also plan to use over 20% of our 2018 capital program for capital workovers on existing well bores. Capital workovers are some of the highest VCI projects in our portfolio and generally include well deepenings, recompletions, changes of lift methods and other activities designed to add incremental productive intervals and reserves.

Further, over 15% of our 2018 capital program is intended for development facilities for our projects, including pipeline and gathering line interconnections, gas compression and water management systems, and about 5% is intended to be used for exploration and to maintain the mechanical integrity, safety and environmental performance of our operations.

9



Reserves and Production Information
The table below summarizes our proved reserves and average net daily production as of and for the year ended December 31, 2017 in each of California's four major oil and gas basins:
 
Proved Reserves as of December 31, 2017
 
Average Net Daily Production for the Year Ended December 31, 2017
 
 
 
Oil (MMBbl)
 
NGLs (MMBbl)
 
Natural Gas (Bcf)
 
Total (MMBoe)
 
Oil (%)
 
Proved Developed (%)
 
(MBoe/d)
 
Oil (%)
 
R/P Ratio (Years)(a)
San Joaquin Basin
265

 
56

 
585

 
419

 
63
%
 
70
%
 
90

 
58
%
 
12.8
Los Angeles Basin
143

 

 
10

 
145

 
99
%
 
72
%
 
27

 
100
%
 
14.7
Ventura Basin
34

 
2

 
26

 
40

 
85
%
 
73
%
 
6

 
67
%
 
18.3
Sacramento Basin

 

 
85

 
14

 

 
86
%
 
6

 
%
 
6.4
Total operations
442

 
58

 
706

 
618

 
72
%
 
71
%
 
129

 
64
%
 
13.1
Note: MMBbl refers to millions of barrels; Bcf refers to billion cubic feet of natural gas; MMBoe refers to million barrels of oil equivalent; and MBoe/d refers to thousands of barrels of oil equivalent per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one Bbl of oil.
(a)
Calculated as total proved reserves as of December 31, 2017 divided by annualized Average Net Daily Production for the year ended December 31, 2017.

Marketing Arrangements

Crude Oil – Substantially all of our crude oil production is connected to California markets via our crude oil gathering pipelines, which are used almost entirely for our production. We generally do not transport, refine or process the crude oil we produce and do not have any significant long-term crude oil transportation arrangements. We currently sell all of our crude oil into the California refining markets, which we believe have offered relatively favorable pricing compared to other U.S. regions for similar grades. In addition, we evaluate opportunities to export our crude oil production. The majority of the oil imported into California arrives via supertanker, with a minor amount arriving by rail. As a result, California refiners have typically purchased crude oil at international waterborne-based prices. Currently, our index-based crude oil sales contracts have 30- to 90-day terms with no such contracts extending past one year.

Natural Gas – California imports approximately 90% of the natural gas consumed in the state. We have firm transportation capacity contracts to access markets and to facilitate deliveries. We sell virtually all of our natural gas production under individually negotiated contracts using market-based pricing on a monthly or shorter basis.

NGLs – We extract substantially all of our NGLs through our gas processing plants, which facilitate access to third-party delivery points near the Elk Hills field. We currently have pipeline capacity contracts to transport 20,000 barrels per day of NGLs to market. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to one-year contracts that are renewed annually. Approximately 36% of our NGLs are sold to export markets.

Electricity – Part of the electrical output of the Elk Hills power plant operated by one of our subsidiaries is used by the Elk Hills field, which reduces operating costs and increases reliability. We sell the excess to the grid and to utilities.

Hedging
We maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices and to improve our ability to comply with the covenants under our credit facilities. We will continue to be strategic and opportunistic in implementing our hedging program. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not necessarily accounted for as cash-flow or fair-value hedges. For more on our current derivative contracts, see Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.



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Our Principal Customers

We sell crude oil, natural gas and NGLs to marketers, California refineries and other purchasers that have access to transportation and storage facilities. Our ability to sell our products can be affected by factors that are beyond our control, and which cannot be accurately predicted.

For the years ended December 31, 2017 and 2016, our principal customers included Phillips 66 Company, Andeavor (formerly Tesoro Refining & Marketing Company LLC), Valero Marketing & Supply Company and Shell Trading (US) Company, each accounted for at least 10%, and, collectively, 67% of our revenue. For the year ended December 31, 2015, our principal customers included Phillips 66 Company, Tesoro Refining & Marketing Company LLC and Valero Marketing & Supply Company, each accounted for more than 10%, and collectively, 64% of our revenue.

Title to Properties

As is customary in the oil and natural gas industry for acquired properties, we initially conduct a high-level review of the title to our properties at the time of acquisition. Individual properties may be subject to ordinary course burdens that we believe do not materially interfere with the use or affect the value of such properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations, or net profits interests, among others. 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 generally will not commence drilling operations on a property until we have cured known title defects that are material to the project. In addition, substantially all of our properties have been pledged as collateral for our secured debt.

Competition

We encounter strong competition from numerous parties in the oil and gas industry, ranging from small independent producers to major international oil companies. The oil market in California is a captive market with no interstate crude pipeline and rail lines that only run north to south. As a result, 72% of the oil the state consumes is imported, virtually all from waterborne sources. Our proximity to the California refineries gives us a competitive edge through lower transportation costs. The California natural gas market is serviced from a network of pipelines, including interstate and intrastate pipelines. We deliver our natural gas to customers using capacity on our firm transportation commitments.
     
We compete for third-party services to profitably develop our assets, to find or acquire additional reserves, to sell our production and to find and retain qualified personnel. Historically, higher commodity prices intensify competition for drilling and workover rigs, pipe, other oil field equipment and personnel. However, the California energy industry experienced only limited cost inflation in 2017 due to excess capacity in the service and supply sector. Given our relative size compared to other in-state producers, our activity influences the pricing of third-party services in the local market.
Regulation of the Oil and Natural Gas Industry
Our operations are subject to a wide range of federal, state and local laws and regulations. Those that specifically relate to oil and natural gas exploration and production are described in this section.
Regulation of Exploration and Production
Federal, state and local laws and regulations govern most aspects of exploration and production in California, including:
oil and natural gas production, including well spacing on federal, state and private lands;
methods of constructing, drilling, completing, stimulating, operating, maintaining and abandoning wells;
the design, construction, operation, maintenance and decommissioning of facilities, such as natural gas processing plants, power plants, compressors and liquid and natural gas pipelines or gathering lines;
improved or enhanced recovery techniques such as fluid injection for pressure management, waterflooding or steamflooding;
sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and enhanced recovery processes;

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imposition of taxes and fees with respect to our properties and operations;
the conservation of oil and natural gas, including provisions for the unitization or pooling of oil and natural gas properties;
posting of bonds or other financial assurance to drill, operate and abandon or decommission wells and facilities; and
occupational health, safety and environmental matters and the transportation, marketing and sale of our products as described below.

Collectively, the effect of these regulations is to potentially limit the number and location of our wells and the amount of oil and natural gas that we can produce from our wells compared to what we otherwise would be able to do.
The Division of Oil, Gas, and Geothermal Resources (DOGGR) of the Department of Conservation is California's primary regulator of the oil and natural gas industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. The Bureau of Land Management (BLM) of the U.S. Department of the Interior exercises similar jurisdiction on federal lands in California, on which DOGGR also asserts jurisdiction over certain activities. Government actions, including the issuance of certain permits or approvals, by state and local agencies or by federal agencies may be subject to environmental reviews, respectively, under the California Environmental Quality Act or the National Environmental Policy Act (NEPA), which may result in delays, imposition of mitigation measures or litigation. For example, in September 2016, a federal judge issued an order finding that the BLM’s NEPA review of the Resource Management Plan for portions of Ventura, Kern and other counties failed to sufficiently analyze the potential environmental impacts of hydraulic fracturing and directed the BLM to prepare a supplemental environmental impact statement. The result of this NEPA review has the potential to impact future leasing of federal lands in those counties for oil and gas exploration and production activities.
The jurisdiction and enforcement authority of DOGGR and other state agencies have significantly increased with respect to oil and gas activities in recent years, and these agencies have significantly revised their regulations, regulatory interpretations and data collection requirements. DOGGR has undertaken a comprehensive examination of existing regulations and plans to issue additional regulations with respect to certain oil and gas activities in 2018, such as management of idle wells, pipelines and underground fluid injection. Pursuant to Assembly Bill 2729 (AB 2729), DOGGR requires operators annually starting in 2018 to either submit idle well management plans describing how they will plug and abandon or reactivate long-term idle wells or pay additional annual fees for each such well. AB 2729 also requires that DOGGR update its regulations pertaining to idle well testing and management by June 1, 2018. In September 2017, DOGGR proposed regulations that seek to impose more stringent inspection and integrity management requirements on pipelines that are four inches or less in diameter and located in sensitive areas. DOGGR’s plan to update underground injection regulations in 2018, which may address injection approvals, project data requirements, mechanical integrity testing of injection wells, monitoring and reporting requirements with respect to injection parameters, containment or seismic activity, and incident response.
In 2013 California adopted Senate Bill 4 (SB 4), which increased regulation of certain well stimulation techniques, including acid matrix stimulation and hydraulic fracturing, which involves the injection of fluid under pressure into underground rock formations to create or enlarge fractures to allow oil and gas to flow more freely. Among other things, SB 4 requires operators to obtain specific well stimulation permits, make disclosures and implement groundwater monitoring and water management plans. The U.S. Environmental Protection Agency (EPA) and the BLM also regulate certain well stimulation activities, though their regulations are currently being challenged in court. The implementation of federal and state well stimulation regulations has delayed, and increased the cost of, certain operations.

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In addition, certain local governments have proposed or adopted ordinances that would restrict certain drilling activities in general and well stimulation, completion or injection activities in particular, or ban such activities outright. The most onerous of these local measures was adopted in 2016 by Monterey County, where we own mineral interests but do not have any production. The measure prohibits drilling of new oil and gas wells, hydraulic fracturing, other well stimulation and phases out the injection of produced water. This measure was challenged in state court, and the Monterey County Superior Court issued a decision in December 2017, finding that the bans on drilling new wells and water injection are preempted and invalid by existing state and federal regulations and, if implemented, would constitute a taking of our property without compensation under the federal and state constitutions. The court did not rule on the ban on hydraulic fracturing because the court found that the issue was not ripe since hydraulic fracturing is not currently being conducted in Monterey County, noting that the ban could be challenged in the event a hydraulic fracturing is proposed. The decision is expected to be appealed.
Regulation of Health, Safety and Environmental Matters
Numerous federal, state, local, and other laws and regulations that govern health and safety, the release or discharge of materials, land use or environmental protection may restrict the use of our properties and operations, increase our costs or lower demand for or restrict the use of our products and services. Applicable federal health, safety and environmental laws include the Occupational Safety and Health Act, Clean Air Act, Clean Water Act, Safe Drinking Water Act, Oil Pollution Act, Natural Gas Pipeline Safety Act, Pipeline Safety Improvement Act, Pipeline Safety, Regulatory Certainty, and Job Creation Act, Endangered Species Act, Migratory Bird Treaty Act, Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and National Environmental Policy Act, among others. California imposes additional laws that are analogous to, and often more stringent than, such federal laws. These laws and regulations:
establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, and require attainment plans to meet those regional standards, which may include significant restrictions on development, economic activity and transportation in such region;
require various permits, approvals and mitigation measures before drilling, workover, production, underground fluid injection or waste disposal commences, or before facilities are constructed or put into operation;
require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and shutdown systems, to prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;
restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation and reclamation measures, and impose energy efficiency or renewable energy standards on us or users of our products and services;
restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced water or wastes, that can be released or discharged into the environment, or any other uses of those materials resulting from drilling, production, processing, power generation, transportation or storage activities;
limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat and other protected areas, and require the dedication of surface acreage for habitat conservation;
establish standards for the management of solid and hazardous wastes or the closure, abandonment, cleanup or restoration of former operations, such as plugging and abandonment of wells and decommissioning of facilities;
impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment with respect to our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;
impose taxes or fees with respect to the foregoing matters;
may expose us to litigation with government authorities, counterparties, special interest groups or others; and
may restrict our rate of oil, NGLs, natural gas and electricity production.


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Due to the severe drought in California over the last several years, water districts and the state government have implemented regulations and policies that may restrict groundwater extraction and water usage and increase the cost of water. Water management is an essential component of our operations. We treat and reuse water that is co-produced with oil and natural gas for a substantial portion of our needs in activities such as pressure management, waterflooding, steamflooding and well drilling, completion and stimulation. We also provide reclaimed produced water to certain agricultural water districts. We also use supplied water from various local and regional sources, particularly for power plants and to support operations like steam injection in certain fields.

In 2014, at the request of the EPA, DOGGR commenced a detailed review of the multi-decade practice of permitting underground injection wells and associated aquifer exemptions under the Safe Drinking Water Act (SDWA). In 2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the SDWA in certain formations in certain fields. Since the state and the EPA did not complete their review before the state's deadlines, the state announced that it will not rescind permits or enforce the deadlines with respect to many of the formations pending completion of the review, but has applied the deadlines to others. During the review, the state has restricted injection in certain formations or wells in several fields, including some operated by us, requested that we change injection zones in certain fields, and held certain pending injection permits in abeyance. Several industry groups and operators challenged DOGGR’s implementation of its aquifer exemption regulations. In March 2017, the Kern County Superior Court issued an injunction barring the blanket enforcement of DOGGR’s aquifer exemption regulations. The court found that DOGGR must find actual harm results from an injection well’s operations and go through a hearing process before the agency can issue fines or shut down operations.

Separately, the state began a review in 2015 of permitted surface discharge of produced water and the use of reclaimed water for agricultural irrigation, which has led to additional permitting and monitoring requirements in 2017 for surface discharge of produced water. To date, the foregoing regulatory actions have not affected our oil and natural gas production in a material way. These reviews are ongoing, and government authorities may ultimately restrict injection of produced water or other fluids in additional formations or certain wells, restrict the surface discharge or use of produced water or take other administrative actions. The foregoing reviews could also give rise to litigation with government authorities and third parties.

Federal, state and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Regulation of Climate Change and Greenhouse Gas (GHG) Emissions

A number of international, federal, state, regional and local efforts seek to prevent or mitigate the effects of climate change or to track and reduce GHG emissions associated with energy use and industrial activity, including operations of the oil and natural gas production sector and those who use our products as a source of energy. The EPA has adopted federal regulations to:
require reporting of annual GHG emissions from power plants and gas processing plants; gathering and boosting compression and pipeline facilities; and certain completions and workovers;
incorporate measures to reduce GHG emissions in permits for certain facilities; and
restrict GHG emissions from certain mobile sources.

California has adopted the most stringent such laws and regulations. These state laws and regulations:
established a “cap-and-trade” program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030, the year that the cap-and-trade program currently expires;
require allowances or qualifying offsets for GHGs emitted from California operations and for the volume of propane and liquid transportation fuels sold for use in California;
established a low carbon fuel standard, which requires the use of fuels with lower carbon intensities than traditional gasoline and diesel fuels;
impose state goals to derive 50% of California’s electricity from renewable sources and to double the energy efficiency of buildings in the state by 2030; and
impose state goals of reducing emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030.

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The EPA and the California Air Resources Board (CARB) have also expanded direct regulation of methane as a contributor to greenhouse gas emissions. In 2016, the EPA adopted regulations to require additional emission controls for methane, volatile organic compounds and certain other substances for new or modified oil and natural gas facilities. Although the EPA proposed in June 2017 to stay its 2016 methane requirements for two years and revisit their implementation, CARB has adopted more stringent regulations to require monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production, pipeline gathering and boosting facilities and natural gas processing plants beginning in 2018 and additional controls such as tank vapor recovery to capture methane emissions in subsequent years.
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 and other assets.
Regulation of Transportation, Marketing and Sale of Our Products

Our sales prices of oil, NGLs and natural gas in the U.S. are set by the market and are not presently regulated. In late 2015, the U.S. federal government lifted restrictions on the export of domestically produced oil that allows for the sale of U.S. oil production, including ours, in additional markets, which may affect the prices we realize.
Federal and state laws regulate transportation rates for, and marketing and sale of, petroleum products and electricity with respect to certain of our operations and those of certain of our customers, suppliers and counterparties. Such regulations also govern:
interstate and intrastate pipeline transportation rates for oil, natural gas and NGLs in regulated pipeline systems;
prevention of market manipulation in the oil, natural gas, NGL and power markets;
market transparency rules with respect to natural gas and power markets;
the physical and futures energy commodities market, including financial derivative and hedging activity; and
prevention of discrimination in natural gas gathering operations in favor of producers or sources of supply.

The federal and state agencies overseeing these regulations have substantial rate-setting and enforcement authority, and violation of the foregoing regulations could expose us to litigation with government authorities, counterparties, special interest groups and others.
Employees
We had approximately 1,450 employees as of December 31, 2017, of whom approximately 1,070 were employed in field operations. Approximately 70 of our employees are represented by labor unions. We have not experienced any strikes or work stoppages by our employees since our formation in 2014. We also utilize the services of independent contractors to perform drilling, well work, operations, construction and other services, including construction contractors whose workforce is often represented by labor unions.

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Spin-Off and Reverse Stock Split
We were incorporated in Delaware as a wholly owned subsidiary of Occidental on April 23, 2014, and remained a wholly owned subsidiary of Occidental until November 30, 2014 when Occidental distributed shares of our common stock on a pro-rata basis to Occidental stockholders (the Spin-off). On December 1, 2014, we became an independent, publicly traded company. Occidental initially retained approximately 18.5% of our outstanding shares of common stock, which were distributed to its stockholders on March 24, 2016. All references to ‘‘Occidental’’ refer to Occidental Petroleum Corporation, our former parent, and its subsidiaries.
On May 31, 2016 we completed a reverse stock split using a ratio of one share of common stock for every ten shares then outstanding. Share and per share amounts included in this report have been restated to reflect this reverse stock split.
Available Information
We make the following information available free of charge on our website at www.crc.com:
Forms 10-K, 10-Q, 8-K and amendments to these forms as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC);
Other SEC filings including Forms 3, 4 and 5;
Corporate governance information, including our corporate governance guidelines, board-committee charters and code of business conduct (see Item 10 – Directors, Executive Officers and Corporate Governance for further information); and
Other important additional information, including GAAP to non-GAAP reconciliations.
Information contained on our website is not part of this report.
ITEM 1A
RISK FACTORS

RISK FACTORS

We are subject to certain risks and hazards due to the nature of our business activities. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows and results of operations, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may ultimately materially and adversely affect our business, financial condition, cash flows and results of operations.

Commodity pricing can fluctuate widely and strongly affects our results of operations, financial condition, cash flow and ability to invest in our assets.

Our results of operations, financial condition, cash flow and ability to invest in our assets are highly dependent on commodity prices. Compared to early to mid-2014, global energy commodity prices have declined significantly. We are particularly dependent on Brent crude prices that have declined from over $110 per barrel in June 2014 to below $30 per barrel in January 2016. Brent prices have improved since early 2016 and averaged $54.82 in 2017. However, such improvements may not continue or may be reversed. Continued low prices for our products or further price decreases could have several adverse effects including:

reduced cash flow and decreased funds available for capital investments, interest payments and operational expenses;
reduced proved oil and gas reserves over time and related cash flows;
impairments of our oil and gas properties;
reduced borrowing base capacity under our 2014 Revolving Credit Facility as proved oil and gas reserves values fall;
the potential for a reduction of our liquidity, mandatory loan repayments and default and foreclosure by our banks and bondholders against our secured assets;
forced monetization events and potential issues under our JV arrangements;
inability to attract counterparties to our transactions, including hedging transactions; and
inability to access funds through the capital markets and the price we could obtain for, or the ability to conduct, asset sales or other monetization transactions.

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Commodity pricing can fluctuate widely and is affected by a variety of factors, including changes in consumption patterns; inventory levels; global and local economic conditions; the actions of OPEC and other significant producers and governments; actual or threatened production, refining and processing disruptions; worldwide drilling and exploration activities; the effects of conservation; weather, geophysical and technical limitations; currency exchange rates; technological advances; transportation and storage capacity, bottlenecks and costs in producing areas; alternative energy sources; regional market conditions; other matters affecting the supply and demand dynamics for our products; and the effect of changes in these variables on market perceptions. These and other factors make it impossible to predict realized prices reliably. While our hedging activities provide some downside protection for a significant portion of our 2018 production, they may not adequately protect us from commodity price reductions and we may be unable to enter into acceptable additional hedges.

Our lenders require us to comply with covenants and can limit our borrowing capabilities, which may materially limit our ability to use or access capital and our business activities.

Our ability to borrow funds under our 2014 Revolving Credit Facility is limited by our borrowing base, the size of our lenders' commitments, our ability to comply with covenants and a minimum monthly liquidity requirement of $150 million. Currently, the lenders' aggregate commitment under our 2014 Revolving Credit Facility is $1 billion, and we had approximately $850 million in availability, before taking into account the minimum liquidity requirement. We may need to draw on our 2014 Revolving Credit Facility for a portion of our future capital or operating needs.

The financial covenants that we must satisfy under our 2014 Revolving Credit Facility include a monthly minimum liquidity test and quarterly first-out leverage, interest expense coverage and first-lien asset coverage ratios. The 2014 Revolving Credit Facility also restricts our ability to monetize assets and issue or purchase debt. Our borrowing base under our 2014 Revolving Credit Facility is redetermined each May 1 and November 1. The borrowing base is determined with reference to a number of factors, including commodity prices and reserves. Restrictions under our 2014 Revolving Credit Facility are further described in Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Credit Agreements.

If we were to breach any of the covenants under our 2014 Revolving Credit Facility, our lenders would be permitted to accelerate the principal amount due under the 2014 Revolving Credit Facility and foreclose against the assets securing them. If payment were accelerated, or we failed to make certain payments, under our 2014 Revolving Credit Facility, it would result in a default under our 2016 and 2017 Credit Agreements and outstanding notes and permit acceleration and foreclosure against the assets securing the 2016 and 2017 Credit Agreements and the Second Lien Notes.

Low commodity prices, coupled with substantial interest payments, could constrain our liquidity. A significant reduction in our liquidity may force us to take actions that could have significant adverse effects.

The primary source of liquidity and resources to fund our capital program and other obligations is cash flow from operations and borrowings under our 2014 Revolving Credit Facility. As noted above, our borrowing capacity is limited.

Further price declines would reduce our cash flows from operations and may limit our access to borrowing capacity or cause a default under our financing agreements. Under these conditions, if we were unable to achieve improved liquidity through additional financing, asset monetizations, restructuring of our debt obligations, equity issuances or otherwise, cash flow from operations and expected available credit capacity could be insufficient to meet our commitments. Successfully completing these actions could have significant adverse effects such as higher operating and financing costs, loss of certain tax benefits or dilution of equity. Past refinancing activities have resulted in increases in our annual interest expense and future refinancing activities may have the same effect.


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We have significant indebtedness that could make us more vulnerable in economic downturns.

As of December 31, 2017, we had long-term consolidated indebtedness of $5.3 billion. Our financing agreements permit us to incur significant additional indebtedness as well as certain other obligations. We may seek amendments or waivers to the extent we need to incur indebtedness above amounts currently permitted by our financing agreements.

Certain of our outstanding indebtedness bears interest at variable rates and a rise in interest rates will increase our interest expense to the extent we do not purchase interest-rate hedges.

Our level of indebtedness may have several important consequences, including:

jeopardizing our ability to execute our business plans;
increasing our vulnerability to adverse changes in our business and in economic and industry conditions;
putting us at a disadvantage against competitors that have lower fixed obligations and more cash flow to devote to their businesses;
limiting our ability to obtain favorable financing for working capital, capital investments and general corporate and other purposes; and
limiting our flexibility to operate our business, compete for capital, react to competitive pressures, and engage in certain transactions that might otherwise be beneficial to us.

Subject to certain exceptions, our financing agreements limit:

incurring additional indebtedness;
repaying junior indebtedness, including our Second Lien Notes and Senior Notes;
making investments;
entering into JVs;
paying dividends and other restricted payments;
creating liens on our assets;
selling assets;
using the proceeds of asset sales for certain purposes;
entering into mergers or acquisitions; and
releasing collateral.

These limitations are further described in Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Credit Agreement; Second Lien Notes; Senior Notes and the documents governing our indebtedness that are filed with the Securities and Exchange Commission (SEC).

Our ability to meet our debt obligations and other financial needs will depend on our future performance, which is influenced by market, financial, business, economic, regulatory and other factors. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or issue additional equity on terms that may be unattractive, if it can be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default. Any of these factors could result in a material adverse effect on our business, financial condition, cash flows or results of operations and a default on our indebtedness could result in acceleration of all of our debt and foreclosure against assets constituting collateral for our secured credit facilities and secured notes.

Our business requires substantial capital investments, which may include acquisitions. 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 gas reserves or production. Our capital investment program is also susceptible to risks that could materially affect its implementation.

The oil and gas industry is capital intensive. We make and expect to increase capital investments for the development and exploration of oil and gas reserves. Our ability to deploy capital as planned depends on a number of variables, including:

commodity prices;
regulatory and third-party approvals;

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our ability to timely drill, complete and stimulate wells;
the availability of, and our ability to compete for, capital, equipment, services and personnel; and
the availability of external sources of financing, including from JVs.

Future capital availability may be reduced by (i) our lenders, (ii) our JV partners, (iii) capital markets constraints, (iv) activist funds or investors or (v) poor stock price performance. Because of these and other potential variables, we may be unable to deploy capital in the manner planned, which may negatively impact our production decline and constrain our development or acquisition activities.

Unless we make sufficient capital investments and conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our ability to make the necessary long-term capital investments or acquisitions needed to maintain or expand our reserves may be impaired to the extent 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.

Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.

Many uncertainties exist in estimating quantities of proved reserves and related future net cash flows. Our estimates are based on various assumptions, which may ultimately prove to be inaccurate.

Generally, lower prices adversely affect the quantity of our reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. In addition, a portion of our proved undeveloped reserves may no longer meet the economic producibility criteria under the applicable rules or may be removed due to a lower amount of capital available to develop these projects within the SEC-mandated five-year limit.

In addition, our reserves information represents estimates prepared by internal engineers. Although over 80% of our 2017 proved reserve estimates were audited by our independent petroleum engineers, Ryder Scott Company, L.P., we cannot guarantee that the estimates are accurate. Reserves estimation is a partially subjective process of estimating accumulations of oil and natural gas. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows from those reserves depend upon a number of variables and assumptions, including:

historical production from the area compared with production from similar areas;
the quality, quantity and interpretation of available relevant data;
commodity prices;
production and operating costs;
ad valorem, excise and income taxes;
development costs;
the effects of government regulations; and
future workover and asset retirement costs.

Changes in these variables and assumptions could require us to make significant negative reserves revisions, which could affect our liquidity by reducing the borrowing base under our 2014 Revolving Credit Facility. In addition, factors such as the availability of capital, geology, government regulations and permits, the effectiveness of development plans and other factors could affect the source or quantity of future reserves additions.

Risks related to our acquisition and disposition activities could adversely impact our financial condition and results of operations.

Our acquisition activities carry risks that we may: (i) not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances; (ii) bear unexpected integration costs or experience other integration difficulties; (iii) experience share price declines based on the market’s evaluation of the activity and (iv) assume liabilities that are greater than anticipated. Furthermore, any acquisitions made in foreign countries would expose us to currency, political, marketing, labor and other risks associated with investments in foreign assets.

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In connection with our acquisitions, we are often only able to perform limited due diligence. Successful acquisitions of oil and gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing for recovering the reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact and incomplete, and we may be unable to make these assessments with a high degree of accuracy.

Our disposition activities, including JVs, carry risks that we may (i) not be able to realize reasonable prices or rates of return for assets we sell or contribute to JVs; (ii) be required to retain liabilities that are greater than desired or anticipated; (iii) experience increased operating costs and (iv) burden our cash flows and borrowing base if we cannot replace the revenue lost for less than the proceeds from the disposition, or at all.

Our business is highly regulated and government authorities can delay or deny permits and approvals or change legal requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and 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 the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products. Federal, state and local agencies may assert overlapping authority to regulate in these areas. For example, the jurisdiction and enforcement authority of various state agencies have significantly increased with respect to oil and gas activities in recent years, and these agencies have significantly revised their regulations, regulatory interpretations and data collection and plan to issue additional regulations of certain oil and gas activities in 2018. In addition, certain of these federal, state and local laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

See Item 1 – Business – Regulation of the Oil and Natural Gas Industry 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, stimulation, operation, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, fluid injection and disposal and water recycling and reuse. Failure to comply may result in the assessment of administrative, civil and/or 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 prohibiting certain operations. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

Our customers, including refineries and utilities, and the businesses that transport our products to customers are also highly regulated. For example, 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 has adopted additional regulations on the storage of natural gas that could affect the demand for or availability of such storage, increase seasonal volatility, or otherwise affect the prices we receive from customers.

Costs of compliance may increase and operational delays or restrictions may occur as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations, each of which has occurred in the past.
 
Government authorities and other organizations continue to study health, safety and environmental aspects of oil and 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 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, preclude us from drilling, completing or stimulating wells, or otherwise restrict our ability to access and develop mineral rights, any of which could have an adverse effect on our expected production, other operations and financial condition.

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For recent examples relating to well stimulation, water management and fluid injection see Item 1 - Business - Regulation of the Oil and Natural Gas Industry.

Changes in elected officials could result in different approaches to the regulation of the oil and gas industry. In 2018, California will elect a new governor who will take office next year. Representatives in the California legislature will change. We cannot predict the actions the future governor or legislature may take with respect to the regulation of our business, the oil and gas industry or the state's economic fiscal or environmental policies.

Drilling for and producing oil and natural gas carry significant operational and financial risk and uncertainty. We may not drill wells at the times we scheduled, or at all, and wells we do drill may not yield production in economic quantities or generate our expected VCI.

Our decisions to explore, develop, purchase or otherwise exploit prospects or properties depend in part on the evaluation of geophysical, geologic, engineering, production and other technical data and processes. The analysis of these factors is often inconclusive or subject to varying interpretations. Our decisions and ultimate profitability are also affected by commodity prices, the availability of capital, regulatory approvals, available transportation and storage capacity, political resistance and other factors. Our cost of drilling, completing, stimulating, equipping, operating, maintaining and abandoning wells is also often uncertain. As we enter into more JVs, our ability to ramp up and deploy internal capital may be constrained. Our production cost per barrel is higher than that of many of our peers due to the extraction methods we use, the large number of wells we operate and the effects of our PSC contracts. Overruns in budgeted investments are a common risk that can make a particular project uneconomic or less economic than forecast. We bear the risks of equipment failures, accidents, environmental hazards, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes, disappointing drilling results or reservoir performance, including production response to improved recovery or enhanced recovery efforts, and other associated risks. The VCI metric we use to allocate capital is based on estimates of future cash flows and capital investment, and therefore our projects may not generate the expected results.

We have specifically identified locations for drilling over the next several years, which represent a significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate. We cannot guarantee that these exploration drilling locations or any other drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these drilling locations. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring in the next three years represented approximately 16% of our total net undeveloped acreage at December 31, 2017.

Part of our strategy involves exploratory drilling, including drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.

The risk profile for our exploration drilling locations is higher than for other locations because we have less geologic and production data and drilling history, in particular those exploration drilling locations in unconventional reservoirs. We may not find commercial amounts of oil or natural gas, in which case the value of our undeveloped acreage may decline and could be impaired. In 2017, we drilled two exploration wells both of which were dry. We may increase the proportion of our drilling in new or emerging plays over time.

One of our important assets is our acreage in the Monterey shale play in the San Joaquin, Los Angeles and Ventura basins. The geology of the Monterey shale is highly complex and not uniform due to localized and varied faulting and changes in structure and rock characteristics. As a result, it differs from other shale plays that can be developed in part on the basis of their uniformity. Instead, individual Monterey shale drilling sites may need to be more fully understood and may require a more precise development approach, which could affect the timing, cost and our ability to develop this asset.


21



Our commodity-price risk-management activities may prevent us from fully benefiting from price increases and may expose us to other risks.

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.

Adverse tax law changes may affect our operations.

In California, there have been proposals for new taxes on oil and gas production. Although the proposals have not become law, campaigns by various interest groups could lead to future additional oil and gas severance or other taxes such as extending the state's retail sales tax to many services used in business. In addition to the existing state corporate tax rate of 8.84%, California state lawmakers recently proposed a 10% surcharge on companies with taxable income of over $1 million. The imposition of such taxes could significantly reduce our profit margins and cash flow and could ultimately reduce our capital investments and growth plans.

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

Our operations are concentrated in California. Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions. These include local price fluctuations, changes in state or regional laws and regulations affecting our operations and other regional supply and demand factors, including gathering, pipeline, transportation and storage capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. The concentration of our operations in California and limited local storage options also increase our exposure to events such as natural disasters, mechanical failures, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs, prevent development of lease inventory before expiration and limit access to markets for our products.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to reduce the effect of risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (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. Among other things, the Dodd-Frank Act required the U.S. Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may enter and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices.

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 impacted by such regulations. At this time, the impact of such regulations is not clear.

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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 increasing the costs to provide our products and services, and reducing demand for, and consumption of, our products and services, and we may be unable to recover or pass through a significant portion of our costs. In addition, legislative and regulatory responses to such issues may increase our operating costs and render certain wells or projects uneconomic, and potentially lower the value of our reserves and other assets. As these requirements become more stringent, we may be unable to implement them in a cost-effective manner. 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 the EPA and California have implemented laws, regulations and policies that seek to reduce GHG emissions as discussed in Item 1 – Business – Regulation of the Oil and Natural Gas Industry. In 2017, we incurred costs of approximately $27 million for mandatory GHG emissions allowances in California, and costs of such allowances per metric ton of GHG emissions are expected to increase in the future as CARB tightens program requirements or as the minimum state auction price of such allowances is increased.

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, electricity generation and other applications, prohibit future use of certain vehicles and equipment that require petroleum fuels, impose additional taxes and costs on producers and consumers of petroleum products and require or subsidize the use of renewable energy. Various claimants, including certain municipalities, have also filed litigation alleging that energy producers are liable for conditions the claimants attribute to climate change.

Governmental authorities can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. In addition, California air quality laws and regulations, particularly in southern and central California where most of our operations are located, are in most instances more stringent than analogous federal laws and regulations. For example, the San Joaquin Valley will be required to adopt more rigorous attainment plans under the Clean Air Act to comply with federal ozone and particulate matter standards, and these efforts could affect our activities in the region and our ability to permit new or modified operations.

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 gas exploration and production activities are subject to risks such as fires, explosions, releases, discharges, equipment or information technology failures and industrial accidents. In addition, catastrophic events such as earthquakes, floods, mudslides, wildfires or droughts, cyber or terrorist attacks and other events may cause operations to cease or be curtailed and may adversely affect our business, workforce 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.

Information technology failures and cyber attacks 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. Cyber attacks on businesses have escalated in recent years. 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.

23




We are exposed to certain risks related to our separation from Occidental in 2014.

In connection with our separation from Occidental, we entered into contracts that allocate risks and liabilities (including tax liabilities) between Occidental and ourselves. These contracts were not made on an arm’s length basis and include mutual indemnity obligations. Indemnity payments that we may be required to provide Occidental may be significant and could adversely impact our business. Similarly, third parties could also seek to hold us responsible for liabilities that Occidental has agreed to retain and the indemnity from Occidental may not be sufficient or paid timely.

ITEM 1B
UNRESOLVED STAFF COMMENTS

We have no unresolved SEC staff comments at December 31, 2017.

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ITEM 2
PROPERTIES

Our Operations
Our Areas of Operation
California is one of the most prolific oil and natural gas producing regions in the world and is currently the fifth largest oil producing state in the nation. According to DOGGR information through 2016, cumulative California production from all four basins in which we operate is 36 billion barrels of oil equivalent (BBoe), including approximately 20 BBoe in the San Joaquin basin, 11 BBoe in the Los Angeles basin, 3 BBoe in the Ventura basin and 2 BBoe in the Sacramento basin. Additionally, Kern County has been one of the top two largest oil producing counties in the lower 48 states for a number of years. Our operations include 135 fields with 8,636 gross producing wells as of December 31, 2017. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net mineral acres. Approximately 60% of our total net mineral interest position is held in fee and 15% is held by production. A majority of our interests are in producing properties located in reservoirs characterized by what we believe to be long-lived production profiles with repeatable development opportunities.
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12085695&doc=16

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In 2017, we produced 47 million barrels of oil equivalent (MMBoe). We added 56 MMBoe in proved reserves in 2017, comprising 22 MMBoe from positive performance revisions and 34 MMBoe from extensions and discoveries, representing a 119% organic reserves replacement ratio. This was accomplished with a $371 million capital program, of which $362 million was directed to development activities. In addition, positive price-related revisions added another 49 MMBoe of reserves. For further information on our reserves replacement ratio, see Our Reserves – PV-10, Standardized Measure and Reserves Replacement Ratio section below.
San Joaquin Basin
We actively operate and are developing 46 fields in this inland basin in the southern part of California's central valley. Our assets consist of conventional primary, IOR, EOR and unconventional project types with approximately 1.5 million net mineral acres, approximately 66% of which we hold in fee and another 7% is held by production. Approximately 68% of our estimated proved reserves as of December 31, 2017 were located in, and 70% of our average daily net production for the year ended December 31, 2017 came from, the San Joaquin basin.
According to DOGGR, approximately 75% of California’s daily oil production for 2016 was produced in the San Joaquin basin. Commercial petroleum development began in the basin in the 1800s. Rapid discovery of many of the largest oil accumulations followed during the next several decades, including the Elk Hills field. We have been redeveloping this field and building our expertise to use in other fields across the state. According to the U.S. Geological Survey as of 2012, the San Joaquin basin contained three of the 10 largest oil fields in the United States based on cumulative production and proved reserves. We have been successfully developing steamfloods in our Kern Front operations, which are located next to the giant Kern River field, and in the northwest portion of the Lost Hills field. Beginning in the 1980s, reserves additions occurred in the Monterey formation on the west side of the basin and in our new conventional field discoveries. The basin contains multiple stacked formations throughout its areal extent, and we believe that the San Joaquin basin provides an appealing inventory of existing field re-development opportunities, as well as new play discovery and unconventional play potential. The complex stratigraphy and structure in the San Joaquin basin has allowed continuing discoveries of stratigraphic and structural traps. We believe our extensive 3D seismic library, which covers nearly 3,000 square miles in the San Joaquin basin, including 50% of our acreage, will give us a competitive advantage in further exploring this basin.
We have established a large ownership interest in several of the largest existing oil fields in the San Joaquin basin, including Elk Hills, our largest producing field, as well as the Buena Vista and Kettleman North Dome fields.
Elk Hills
Elk Hills is one of the largest fields in the continental United States based on proved reserves and has produced approximately 2.0 BBoe to date. During the year ended December 31, 2017, we produced 48 MBoe/d on average from the Elk Hills properties, or approximately 37% of our total average daily production. Of our total Elk Hills production, 67% is liquids. We also operate efficient natural gas processing facilities, including a state-of-the-art cryogenic gas plant, with a combined gas processing capacity of over 520 MMcf/d. Additionally, one of our subsidiaries generates sufficient electricity to operate the field and sells the excess power to the grid and to utilities. A portion of the excess power is subject to a five-year contract with a local utility, which includes a minimum capacity payment, that provides rates that are better than those that could be received from sales to the grid. Our operations at Elk Hills include a state-of-the-art central control facility and remote automation control on over 95% of our wells in this field.
Los Angeles Basin
We actively operate and are developing 8 fields in this urban, coastal basin which consists of IOR project types, approximately half of which we hold in fee and 52% held by production. Approximately 23% of our estimated proved reserves as of December 31, 2017 were located in, and 20% of our average daily net production for the year ended December 31, 2017 came from, the Los Angeles basin.
The basin is a northwest-trending plain about 50 miles long and 20 miles wide. Most of the significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has one of the highest concentrations per acre of crude oil in the world with 68 fields in an area of about 0.3 million acres. The basin contains multiple stacked formations throughout its depths, and we believe that the Los Angeles basin provides a considerable inventory of existing field re-development opportunities as well as new play discovery potential. Large active oil fields include the Wilmington and Huntington Beach fields, where we have significant operations.

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Wilmington Field
The Wilmington field located in Long Beach is the fourth largest field in the United States and has produced approximately 3.0 BBoe to date. During the year ended December 31, 2017, we produced approximately 30 MBoe/d gross on average, or 98% of the Wilmington field's daily production from all producers for the year. We operate in this field on behalf of the state of California and the city of Long Beach. Our net production in 2017 of approximately 23 MBoe/d equated to approximately 18% of our total average daily production. Most of our Wilmington production is subject to a set of contracts similar to production-sharing contracts under which we recover the capital and operating costs we incur on behalf of the state and the city of Long Beach and receive our share of profits. We use waterflood recovery methods to develop the field. Our waterflood operations have attractive margins and returns in the current price environment and extend the productive life of our reservoirs beyond the economic life expected for primary development.
Ventura Basin
We actively operate and are developing 28 fields in this central California coastal basin which consists of primary conventional, IOR, EOR and unconventional project types. We currently hold approximately 0.2 million net mineral acres in the Ventura basin, approximately 73% of which we hold in fee and 11% held by production. Approximately 6% of our estimated proved reserves as of December 31, 2017 were located in, and approximately 5% of our average daily net production for the year ended December 31, 2017 came from, the Ventura basin.
The Ventura basin is the onshore part of a structural feature and its offshore extension is the modern Santa Barbara basin. All of the sedimentary section is productive at various locations, and most reservoirs are sandstones with favorable porosity and permeability. The basin contains multiple stacked formations throughout its depths, and we believe that the Ventura basin provides an appealing inventory of existing field re-development opportunities, as well as new exploration potential.
Sacramento Basin
We actively operate and are developing 53 fields in this inland basin in the northern part of California's central valley, primarily consisting of dry gas production. We currently hold approximately 0.5 million net mineral acres in the Sacramento basin, approximately 38% of which we hold in fee and 44% held by production. We believe our significant acreage position in the Sacramento basin gives us the option for future development and rapid production growth in an attractive natural gas price environment. As of December 31, 2017, approximately 2% of our estimated proved reserves were located in the Sacramento basin, which accounted for approximately 5% of our average daily net production for the year.
The Sacramento basin is a deep, thick sequence of sedimentary deposits within an elongated northwest-trending structural feature covering about 7.7 million acres. Exploration and development in the basin began in 1918.
Conventional Reservoir Recovery Methods
We determine which development method to use based on reservoir characteristics, reserves potential and expected returns. We seek to optimize the potential of our conventional assets by progressively using primary recovery methods, which may include some well stimulation techniques, IOR methods like waterflooding and EOR methods such as steamflooding, using both vertical and horizontal drilling. All of these techniques are proven technologies we have used extensively in California.
Primary Recovery
Primary recovery is a reservoir drive mechanism that utilizes the natural energy of the reservoir and is the first technique we use to develop a reservoir. Primary recovery is achieved by drilling and producing wells without supplementing the natural energy of the reservoir. Our successful exploration program continues to provide us with primary recovery opportunities in new reservoirs or through extensions of existing fields. Our conventional development programs create future opportunities to convert these reservoirs to waterfloods or steamfloods after their primary production phase.

27



Waterfloods
Some of our fields have been partially produced and no longer have sufficient energy to drive oil to our producing wellbores. Waterflooding is a well understood process that has been used in California for over 50 years to re-introduce energy to the reservoir through water injection and to sweep oil to producing wellbores. This process has been known to increase recovery factors from approximately 10% under primary recovery methods to up to approximately 20%. Our waterflood operations have attractive margins and returns in the current price environment. These operations typically have low and predictable production declines and allow us to extend the productive life of a reservoir and significantly increase our incremental recovery after primary recovery. As a result, investments in waterfloods can yield attractive returns even in a low price environment. We use waterfloods extensively in the San Joaquin, Los Angeles and Ventura basins, which has allowed us to reduce production declines or modestly grow our production from mature fields such as Elk Hills and Wilmington.
Steamfloods
Some of our fields contain heavy, thick oil. Steamfloods work by injecting steam into the reservoir to heat the oil, decreasing its viscosity, or thinning the oil, allowing it to flow more easily to the producing wellbores. Steamflooding is a well understood process that has been used in California since the early 1960s. This process has been known to increase recovery factors from approximately 10% under primary recovery methods to up to approximately 75%. Thermal operations are most effective in shallow reservoirs containing heavy, viscous oil. The steamflood process is generally characterized by low capital investment with attractive margins and returns even in a low oil price environment as long as the oil-to-gas price ratio is in excess of five. The economics of steamflooding are largely a function of the ratio between oil and natural gas prices. After drilling, these operations typically ramp up production over one to two years as the steam continues to influence the oil production, and then exhibit a plateau for several months, with a subsequent low, predictable production decline rate of 5 to 10% per year. This gradual decline allows us to extend the productive life of a reservoir and significantly increase our incremental recovery after primary depletion. We use steamfloods extensively in the San Joaquin basin, where they have allowed us to grow our production from mature fields such as Kern Front and Lost Hills, among others.
Unconventional Reservoir
We believe our undeveloped unconventional acreage has the potential to provide significant long-term production growth. In total, we hold mineral interests in approximately 1.3 million net mineral acres with unconventional potential and have identified over 4,930 gross (4,530 net) unconventional drilling locations on this acreage. As a result of our development efforts in previous years, approximately 34% of our 2017 production was from unconventional reservoirs, an increase of approximately 91% since the acquisition of the Elk Hills field properties in 1998. As of December 31, 2017, we had proved reserves of approximately 180 MMBoe associated with our unconventional properties, approximately 26% of which were proved undeveloped reserves.
We hold significant interests in the Monterey formation, which is divided into upper and lower intervals. We have successfully produced from seven discrete stacked pay horizons within the upper Monterey. During the year ended December 31, 2017, we produced approximately 53 MBoe/d on average from upper Monterey. The lower Monterey is recognized as a world-class source rock but has an extremely limited production history compared to the upper Monterey, and therefore very limited knowledge exists regarding its potential. For example, only about 25 wells have tested the lower Monterey to date. However, we believe we will be able to apply knowledge we gain from the upper Monterey to the lower Monterey.
Prior to the severe price declines that began in late 2014, we were focused on higher-value unconventional production from seven discrete stacked pay horizons within the Monterey formation, primarily within the upper Monterey. As commodity prices and project economics improved in 2017, we continued our development activities in the upper Monterey formation and started to appraise and delineate the Kreyenhagen formation within our Kettleman North Dome field. We expect to continue pursuing unconventional opportunities in 2018 and beyond if prices remain at current levels. Over the longer term, as project economics improve, we will seek to duplicate our successful upper Monterey results to develop opportunities in the unconventional reservoirs of the lower Monterey, Kreyenhagen and Moreno formations, which have similar geological attributes.

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Exploration Program
We have had a successful exploration program in both conventional and unconventional plays, including during the years prior to Spin-off. Our experienced technical staff, proprietary geological models, leading acreage position and extensive 3D seismic library give us a strong competitive advantage. California is one of the most prolific hydrocarbon producing regions as a result of its world-class source rocks and stacked conventional and unconventional reservoirs. California basins have generated billions of barrels of oil and have established production from over 400 identified reservoir intervals in both structural and stratigraphic trap configurations. Historical industry activity has focused on the primary and secondary development of known hydrocarbon accumulations, many of which were discovered over a century ago. We have significant land positions in under-explored hydrocarbon basins.
We continue to focus on growing our exploration drilling locations and resource identification. We have a ranked near-field portfolio of over 150 exploration prospects across the San Joaquin, Sacramento and Ventura basins. As of December 31, 2017, we had approximately 12,610 gross (5,670 net) exploration drilling locations in conventional reservoirs and approximately 6,400 gross (5,300 net) exploration drilling locations in unconventional reservoirs.
During 2017, we drilled five shallow wells targeting heavy oil accumulations in the San Joaquin basin . All wells encountered hydrocarbons and confirmed potential future development areas. Two of the exploration wells are currently producing, and three of the wells were considered data wells and were plugged and abandoned.
In 2017, we also partnered with third parties in some of our exploration activities, some of which are not included in our consolidated results. These arrangements allow us to defer some of our exploration costs and mitigate technical risks. With a JV partner, we drilled a successful exploration well in a conventional reservoir in the southern San Joaquin basin to a depth of approximately 15,000 feet, which targeted a seismic defined stratigraphic trap in the prolific Stevens Sand reservoir. The initial flow rate of the well was in excess of 300 barrels of oil a day. In connection with this JV, we also acquired 3D seismic data in developed fields that highlighted a number of additional new leads.
At year end, we were in the process of drilling an exploration well in the Sacramento basin. The well encountered multiple stacked gas bearing reservoirs totaling approximately 400 feet in gross thickness. The higher quality reservoirs exhibit porosities ranging from 15% to 20%. An effective well testing program is being planned and will be executed in 2018.
Our Reserves
The information with respect to our estimated reserves presented below has been prepared in accordance with the rules and regulations of the SEC.
Proved oil, NGLs and natural gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year (SEC prices), unless prices were defined by contractual arrangements. Oil, NGLs and natural gas prices used for this purpose were based on spot prices, adjusted for price differentials to account for gravity, quality and transportation costs. For the 2017 reserves estimates, the calculated average Brent oil price was $54.42 per barrel and the average NYMEX gas price was $2.98 per Million British Thermal Units (MMBtu). The average realized prices used for the 2017 disclosures were $51.74 per barrel for oil, $35.05 per barrel for NGLs and $2.59 per Mcf for natural gas.

29



The following table sets forth our net operating and non-operating interests in quantities of proved developed and undeveloped reserves of oil (including condensate), natural gas liquids (NGLs) and natural gas as of December 31, 2017. Estimated reserves include our economic interests under arrangements similar to production-sharing contracts at our Wilmington field in Long Beach.
 
As of December 31, 2017
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
Proved developed reserves:
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
176

 
104

 
24

 

 
304

NGLs (MMBbl)
43

 

 
2

 

 
45

Natural Gas (Bcf)
447

 
6

 
20

 
70

 
543

Total (MMBoe)(a)(b)
294

 
105

 
29

 
12

 
440

 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
89

 
39

 
10

 

 
138

NGLs (MMBbl)
13

 

 

 

 
13

Natural Gas (Bcf)
138

 
4

 
6

 
15

 
163

Total (MMBoe)(b)
125

 
40

 
11

 
2

 
178

 
 
 
 
 
 
 
 
 
 
Total proved reserves:
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
265

 
143

 
34

 

 
442

NGLs (MMBbl)
56

 

 
2

 

 
58

Natural Gas (Bcf)
585

 
10

 
26

 
85

 
706

Total (MMBoe)(b)
419

 
145

 
40

 
14

 
618

(a)
As of December 31, 2017, approximately 21% of proved developed oil reserves, 9% of proved developed NGLs reserves, 15% of proved developed natural gas reserves and, overall, 19% of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full peak production response has not yet occurred due to the nature of such projects.
(b)
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of gas and one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

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Proved Reserves Additions

The components of the changes to our proved reserves (in MMBoe) during the years ended December 31, 2017, 2016 and 2015 were as follows:
 
San Joaquin Basin
 
Los Angeles Basin(a)
 
Ventura Basin
 
Sacramento Basin
 
Total
Balance at December 31, 2014
525

 
166

 
58

 
19

 
768

Revisions related to price
(50
)
 
(85
)
 
(12
)
 
(6
)
 
(153
)
Revisions related to performance
(8
)
 
51

 
(1
)
 
3

 
45

Improved recovery
3

 

 

 

 
3

Extensions and discoveries
15

 
12

 
5

 
1

 
33

Purchases
6

 

 

 

 
6

Sales

 

 

 

 

Production
(40
)
 
(12
)
 
(3
)
 
(3
)
 
(58
)
Balance at December 31, 2015
451

 
132

 
47

 
14

 
644

Revisions related to price
(17
)
 
(23
)
 
(20
)
 

 
(60
)
Revisions related to performance
12

 

 
2

 
(1
)
 
13

Improved recovery
3

 

 

 

 
3

Extensions and discoveries
16

 
1

 
3

 

 
20

Purchases

 

 

 

 

Sales

 
(1
)
 

 

 
(1
)
Production
(36
)
 
(10
)
 
(3
)
 
(2
)
 
(51
)
Balance at December 31, 2016
429

 
99

 
29

 
11

 
568

Revisions related to price
16

 
23

 
9

 
1

 
49

Revisions related to performance
(6
)
 
24

 
2

 
2

 
22

Improved recovery

 

 

 

 

Extensions and discoveries
19

 
9

 
4

 
2

 
34

Purchases

 

 

 

 

Sales
(6
)
 

 
(2
)
 

 
(8
)
Production
(33
)
 
(10
)
 
(2
)
 
(2
)
 
(47
)
Balance at December 31, 2017
419

 
145

 
40

 
14

 
618

Note: Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one Bbl of oil.
(a)
Includes proved reserves related to economic arrangements similar to PSCs of 108 MMBbl, 85 MMBbl, 103 MMBbl and 116 MMBbl at December 31, 2017, 2016, 2015 and 2014, respectively.

Our ability to add reserves, other than through purchases, depends on the success of improved recovery, extension and discovery projects, each of which depends on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside management's control, and will affect whether the historical sources of proved reserves additions continue to provide reserves at similar levels.

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. Partially offsetting this effect, higher prices decrease our share of proved cost recovery reserves under arrangements similar to production-sharing contracts at our Wilmington field in Long Beach because fewer reserves are required to recover costs. Conversely, when prices drop, we experience the opposite effects. In 2017, our total net positive price revision was 49 MMBoe, which was primarily the result of higher prices net of modestly higher operating costs due to the current commodity price environment, partially reinstating reserves that were removed in prior years due to lower prices. In 2016 and 2015, total net negative price revisions were 60 MMBoe and 153 MMBoe, respectively. The 2016 and 2015 price revisions incorporated the negative effect of lower prices, partially offset by the positive effect of lower operating costs also caused by the lower commodity price environment.


31



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 2017, our net positive performance-related revision of 22 MMBoe resulted primarily from the successful renegotiation of our Huntington Beach royalty agreement and improved performance in the San Joaquin basin, partially offset by negative revisions to remove proved undeveloped reserves due to a downward adjustment of our committed capital in a project area and technical revisions due to updated testing results in one of our project areas. In 2016, our positive performance related revisions of 13 MMBoe resulted primarily from better-than-expected reservoir performance and comprehensive field development planning. These positive revisions primarily came from the San Joaquin and Ventura basins. In 2015, our positive performance related revisions of 45 MMBoe resulted primarily from better-than-expected reservoir performance in our San Joaquin and Los Angeles basins, combined with lower development capital than previously estimated.

Improved Recovery

In 2017, there were no material reserves added from improved recovery. We added proved reserves of 3 MMBoe from improved recovery through proven IOR and EOR methods in 2016 and in 2015. The improved recovery additions in both of those years were associated with the continued development of steamflood and waterflood properties in the San Joaquin basin.

Extensions and Discoveries

In 2017, we added 34 MMBoe of proved reserves primarily from extensions, which were associated with the continued successful drilling program mostly in the San Joaquin and Los Angeles basins. Our drilling program in the San Joaquin basin benefited from the deployment of JV capital at Elk Hills and at waterflood projects in Buena Vista. Our drilling program in the Los Angeles basin resulted in expanded economic inventory due to improvements in performance compared to 2016. We also added new projects in the Sacramento basin as a result of analyzing new data from capital workover projects. In 2016 and 2015, we added 20 MMBoe and 33 MMBoe, respectively, of proved reserves from extensions and discoveries, which generally resulted from exploration and development programs primarily in the San Joaquin, Los Angeles and Ventura basins.

Sales

In 2017, we sold 8 MMBoe of proved reserves based on beginning-of-year reserves balances. Included in this amount was 7 MMBoe of proved undeveloped reserves in the San Joaquin basin conveyed to MIRA as part of our JV with MIRA.
Proved Undeveloped Reserves
The total changes to our proved undeveloped reserves during the year ended December 31, 2017 were as follows (in MMBoe):
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
Balance at December 31, 2016
142

 
16

 
4

 

 
162

 
 
 
 
 
 
 
 
 
 
Revisions of previous estimates
 
 
 
 
 
 
 
 
 
   Revisions related to performance
(21
)
 
9

 
(2
)
 

 
(14
)
   Revisions related to price changes
5

 
9

 
5

 

 
19

Total revisions of previous estimates
(16
)
 
18

 
3

 

 
5

 
 
 
 
 
 
 
 
 
 
Extensions and discoveries
15

 
7

 
4

 
2

 
28

 
 
 
 
 
 
 
 
 
 
Sales
(7
)
 

 

 

 
(7
)
 
 
 
 
 
 
 
 
 
 
Transfers to proved developed reserves
(9
)
 
(1
)
 

 

 
(10
)
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2017
125

 
40

 
11

 
2

 
178



32



In 2017, we had 19 MMBoe of positive price-related revisions, partially offset by 14 MMBoe negative performance-related revisions. Our positive price revisions were primarily the result of the higher commodity price environment, partially offset by the effect of modestly higher operating costs. We had negative performance-related revisions primarily resulting from a downward adjustment of our committed capital in a project area and technical revisions due to updated testing results in one of our project areas. These negative performance-related revisions were partially offset by positive revisions related to the successful renegotiation of our Huntington Beach royalty agreement in the Los Angeles basin.

We had proved undeveloped reserves additions of 28 MMBoe primarily from extensions, which were associated with the continued successful drilling program primarily in the San Joaquin and Los Angeles basins. See more discussion of proved reserves additions from the extensions section above.

We transferred 10 MMBoe of proved undeveloped reserves to the proved developed category as a result of the 2017 development program, all of which was in the San Joaquin and Los Angeles basins. As a result, we converted approximately 6% of our beginning-of-year proved undeveloped reserves to proved developed reserves during the year, investing approximately $98 million of capital. The conversion rate reflected the lack of capital in 2016 and only a gradual ramp up of capital during 2017. In addition, 7 MMBoe of our proved undeveloped reserves in the San Joaquin basin were conveyed to the MIRA JV. We expect that, at about $65 to $75 average Brent prices, we will continue to grow our program and have sufficient future capital to develop our proved undeveloped reserves existing at December 31, 2017.

Our year-end development plans and associated proved undeveloped reserves are consistent with SEC guidelines for development within five years. We believe we will have sufficient capital to develop all proved undeveloped reserves within five years of their original booking date and management commitment to do so. Our conclusion is based on $65 average Brent price for 2018, $70 average Brent price for 2019, and $75 thereafter. Prices that are significantly below these levels for a prolonged period could require us to reduce expected capital investment over the next five years, potentially impacting either the quantity or the development timing of proved undeveloped reserves. For example, if the five-year average price remained at $65 Brent, we would need to remove approximately 8% from our proved undeveloped reserves.

PV-10, Standardized Measure and Reserves Replacement Ratio

As of December 31, 2017, our standardized measure of discounted future net cash flows (Standardized Measure) was $3.8 billion and PV-10 was over $4.5 billion. In addition, we organically replaced 119% of our proved reserves in 2017.

PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.
 
As of December 31, 2017
 
($ in millions)
Standardized measure of discounted future net cash flows
$
3,765

Present value of future income taxes discounted at 10%
780

PV-10 of proved reserves
$
4,545

Organic reserves replacement ratio(a)
119
%
(a)
The organic reserves replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery and performance-related revisions, divided by oil-equivalent production. There is no guarantee that historical sources of reserves additions will continue as many factors are fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology, all of which affect reserves additions. Management uses this measure to gauge the results of its capital program. Other oil and gas producers may use different methods to calculate replacement ratios, which may affect comparability.


33



Reserves Evaluation and Review Process

Our estimates of proved reserves and associated discounted future net cash flows as of December 31, 2017 were made by our technical personnel, such as reservoir engineers and geoscientists, with the assistance of operational and financial personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and management's funding commitments to develop the reserves. Reserves volumes are estimated by forecasts of production rates, operating costs and capital investments. Price differentials between specified benchmark prices and realized prices and specifics of each operating agreement are then applied against the SEC Price to estimate the net reserves. Production rate forecasts are derived using a number of methods, including estimates from decline-curve analysis, type-curve analysis, material balance calculations, which take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes, seismic analysis and computer simulations of reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formations being evaluated or in analogous formations. Operating and capital costs are forecast using the current cost environment (without accounting for possible cost changes) applied to expectations of future operating and development activities related to the proved reserves.

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods, for which the incremental cost of any additional required investment is relatively minor. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

Our Vice President, Reserves and Corporate Development has primary responsibility for overseeing the preparation of our reserves estimates. She has over 14 years of experience as an energy sector engineer including as a Senior Reservoir Engineer with Ryder Scott Company, L.P. (Ryder Scott). She is a member of the Society of Petroleum Engineers (SPE) for which she served as past chair of the U.S. Registration Committee. She holds a Master of Business Administration from the Massachusetts Institute of Technology, a Master of Engineering in Petroleum Engineering from the University of Houston and a Bachelor of Science from the University of Florida. She is also a registered Professional Engineer in the state of Texas.

We have an Oil and Gas Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, which reviewed and approved our oil and natural gas reserves for 2017. The Reserves Committee reports to the Audit Committee during the year.

Audits of Reserves Estimates

Ryder Scott was engaged to provide an independent audit of our 2017 and 2016 reserves estimates for fields that in each year comprised at least 80% of our total proved reserves. The primary technical engineer responsible for our audit has 38 years of petroleum engineering experience, the majority of which has been in the estimation and evaluation of reserves. He serves on the Ryder Scott Board of Directors and is a registered Professional Engineer in the state of Texas.

The 2017 reserves audit included a detailed review of 82% of our total proved reserves. For 2017, 2016 and 2015 combined, Ryder Scott audited more than 95% of our total proved reserves. Ryder Scott examined the assumptions underlying our reserves estimates, adequacy and quality of our work product, and estimates of future production rates, net revenues, and the present value of such net revenues. Ryder Scott also examined the appropriateness of the methodologies employed to estimate our reserves as well as their categorization, using the definitions set forth by the SEC, and found them to be appropriate. As part of their process, Ryder Scott developed their own independent estimates of reserves for those fields that they audited. When compared on a field-by-field basis, some of our estimates were greater and some were less than the estimates of Ryder Scott. Given the inherent uncertainties and judgments in estimating proved reserves, differences between our and Ryder Scott's estimates are to be expected. The aggregate difference between our estimates and Ryder Scott's was less than 10%, which was within SPE's acceptable tolerance.


34



In the conduct of the reserves audit, Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, crude oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if anything came to Ryder Scott's attention which brought into question the validity or sufficiency of any such information or data, Ryder Scott would not rely on such information or data until it had resolved its questions relating thereto or had independently verified such information or data.

Ryder Scott determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC as well as the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions. Ryder Scott issued an unqualified audit opinion on our proved reserves at December 31, 2017. Ryder Scott's report is attached as an exhibit to this Form 10-K.

Drilling Locations

Proven Drilling Locations

Based on our reserves report as of December 31, 2017, we have approximately 2,090 gross (1,870 net) drilling locations attributable to our proved undeveloped reserves. We use production data and experience gained from our development programs to identify and prioritize this proven drilling inventory. These drilling locations are included in our inventory only after we have adopted a development plan to drill them within a five-year time frame. As a result of rigorous technical evaluation of geologic and engineering data, we can estimate with reasonable certainty that reserves from these locations will be commercially recoverable in accordance with SEC guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local regulations and other factors it deems relevant in determining such locations.

Unproven Drilling Locations

We have also identified a multi-year inventory of 19,170 gross (17,540 net) drilling locations that are not associated with 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 moved to the proven category. We believe the assumptions and data used to estimate these drilling locations are consistent with established industry practices with well spacing selected based on the type of recovery process we are using.

Exploration Drilling Locations

Conventional – Our exploration portfolio contains approximately 12,610 gross (5,670 net) unrisked prospective drilling locations in conventional reservoirs, the majority of which are located near existing producing fields. We use internally generated information and proprietary geologic models consisting of data from analog plays, 3D 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. Information used to identify exploration locations includes both our own proprietary data, as well as industry data available in the public domain. After defining the potential areal extent of an exploration prospect, we identify our exploration drilling locations within the prospect by applying the well spacing historically utilized for the applicable type of recovery process used in analogous fields.

35




Unconventional – We have approximately 6,400 gross (5,300 net) unrisked prospective resource drilling locations identified in the lower Monterey, Kreyenhagen and Moreno unconventional reservoirs based on screening criteria that include geologic and economic considerations and limited production information. Prospective play areas are defined by geologic data consisting of well cuttings, hydrocarbon shows, open-hole well logs, geochemical data, available 3D or 2D seismic data and formation pressure data, where available. Information used to identify our prospective locations includes both our own proprietary data, as well as industry data available in the public domain. We identify our prospective resource drilling locations based on an assumption of 80-acre spacing per well throughout the prospective area for each resource play.

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 (e.g., primary, waterflood or EOR). Due to the significant vertical thickness and multiple stacked reservoirs usually encountered by our drilling wells, typical well spacing is generally less than 20 acres and often 10 acres or less in the majority of our fields unless specified differently above. These parameters also meet the general well spacing restrictions imposed on certain oil and gas fields in California.

Drilling Schedule

Our identified drilling locations have been scheduled as part of our current multi-year drilling schedule or are expected to be scheduled in the future. However, we may not drill our identified sites at the times scheduled or at all. We view the risk profile for our exploration drilling locations as being higher than for our other drilling locations due to relatively less available geologic and production data and drilling history, in particular with respect to our prospective resource locations in unconventional reservoirs, which are in unproven geologic plays. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate.

Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, capital availability, costs, drilling results, regulatory approvals, available transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. For a discussion of the risks associated with our drilling program, see Item 1A – Risk Factors – Risks Related to Our Business and Industry.

36



The table below sets forth our total gross identified drilling locations as of December 31, 2017, excluding our exploration drilling locations related to unconventional reservoirs.
 
Proven Drilling Locations
 
Total Identified Drilling Locations
 
Oil and
Natural Gas Wells
 
Injection Wells
 
Oil and
Natural Gas Wells
 
Injection Wells
San Joaquin Basin
 

 
 

 
 

 
 

Primary Conventional
120

 

 
8,490

 

Steamflood
660

 
160

 
8,420

 
460

Waterflood
140

 
60

 
2,000

 
990

Unconventional
270

 

 
4,830

 

San Joaquin Basin subtotal
1,190

 
220

 
23,740

 
1,450

 
 
 
 
 
 
 
 
Los Angeles Basin
 

 
 

 
 

 
 

Primary Conventional

 

 

 

Steamflood

 

 

 

Waterflood
410

 
140

 
1,460

 
490

Unconventional

 

 

 

Los Angeles Basin subtotal
410

 
140

 
1,460

 
490

 
 
 
 
 
 
 
 
Ventura Basin
 

 
 

 
 

 
 

Primary Conventional
30

 

 
1,850

 

Steamflood

 

 
120

 

Waterflood
40

 
40

 
1,660

 
580

Unconventional

 

 
100

 

Ventura Basin subtotal
70

 
40

 
3,730

 
580

 
 
 
 
 
 
 
 
Sacramento Basin
 

 
 

 
 

 
 

Primary Conventional
20

 

 
2,420

 

Sacramento Basin subtotal
20

 

 
2,420

 

 
 
 
 
 
 
 
 
Total Identified Drilling Locations
1,690

 
400

 
31,350

 
2,520



37



Production, Price and Cost History
Oil, NGLs and natural gas are commodities, and the price that we receive for our production is largely a function of market supply and demand. Product prices are affected by a variety of factors, including changes in consumption patterns; inventory levels; global and local economic conditions; the actions of OPEC and other significant producers and governments; actual or threatened production; refining and processing disruptions; currency exchange rates; worldwide drilling and exploration activities; the effects of conservation, weather, geophysical and technical limitations; technological advances; transportation and storage capacity, bottlenecks and costs in producing areas; alternative energy sources; regional market conditions; other matters affecting the supply and demand dynamics for our products; and the effect of changes in these variables on market perceptions. Given the volatile oil price environment, as well as our leverage, we have a hedging program to help protect our cash flow and capital investment program.
Fixed and Variable Costs
Our total production costs consist of variable costs that tend to vary depending on production levels, and fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. While a certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. Overall, we believe approximately one-third of our operating costs are fixed over the life cycle of our fields. We actively manage our fields to optimize production and costs. When we see growth in a field we increase capacities, and similarly when a field nears the end of its economic life we manage the costs while it remains economically viable to produce.


38



The following table sets forth information regarding our production, average realized and benchmark prices, and costs for oil and gas producing activities for the years ended December 31, 2017, 2016 and 2015. For additional information on price calculations, see information set forth in Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Production and Prices.
 
Year Ended December 31,
 
2017
 
2016
 
2015
Production Data:
 

 
 

 
 

Oil (MBbl/d)
83

 
91

 
104

NGLs (MBbl/d)
16

 
16

 
18

Natural gas (MMcf/d)
182

 
197

 
229

Average daily combined production (MBoe/d)(a)
129

 
140

 
160

Total combined production (MMBoe)(a)
47

 
51

 
58

 
 
 
 
 
 
Average realized prices:
 

 
 

 
 

Oil prices with hedge ($/Bbl)
$
51.24

 
$
42.01

 
$
49.19

Oil prices without hedge ($/Bbl)
$
51.47

 
$
39.72

 
$
47.15

NGLs prices ($/Bbl)
$
35.76

 
$
22.39

 
$
19.62

Natural gas prices ($/Mcf)(b)
$
2.67

 
$
2.28

 
$
2.66

 
 
 
 
 
 
Average benchmark prices:
 

 
 

 
 

Brent oil ($/Bbl)
$
54.82

 
$
45.04

 
$
53.64

WTI oil ($/Bbl)
$
50.95

 
$
43.32

 
$
48.80

NYMEX gas ($/MMBtu)
$
3.09

 
$
2.42

 
$
2.75

 
 
 
 
 
 
Average costs per Boe:
 

 
 

 
 

Production costs
$
18.64

 
$
15.61

 
$
16.30

Production costs, excluding effects of PSC contracts(c)
$
17.48

 
$
14.69

 
$
15.58

Field general and administrative expenses(d)
$
0.82

 
$
0.84

 
$
1.31

Field general and administrative expenses, adjusted(e)
$
0.72

 
$
0.72

 
$
1.00

Field other operating expenses(d)
$
0.66

 
$
1.02

 
$
1.78

Field other operating expenses, adjusted(f)
$
0.56

 
$
0.67

 
$
0.36

Field depreciation, depletion and amortization(d)
$
10.85

 
$
10.28

 
$
16.72

Field taxes other than on income(d)
$
2.34

 
$
2.36

 
$
2.67

(a)
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas to one Bbl of oil.
(b)
For 2015, the average realized price of gas includes the effect of hedges.
(c)
The reporting of our PSC-like contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. The amounts represent the production costs for the company after adjusting for this difference.
(d)
Amounts exclude corporate charges.
(e)
Amounts exclude corporate charges. Amounts also exclude unusual and infrequent charges related to severance and early retirement costs associated with field personnel totaling $0.10 per Boe, $0.12 per Boe and $0.31 per Boe for 2017, 2016 and 2015, respectively.
(f)
Amounts exclude corporate charges. For 2017, the amounts also exclude net unusual and infrequent charges of $0.10 primarily related to rig termination expenses partially offset by property tax refunds, recovery of amounts due from joint interest partners and other items. For 2016, the amount also excludes net unusual and infrequent gains of $0.35 that include refunds partially offset by plant turnaround charges and other items. For 2015, the amount also excludes charges related to the write-down of certain assets and rig termination charges of $1.42 per Boe.

39



The following table sets forth information regarding production, realized prices and production costs for our largest two fields, Elk Hills and Wilmington, for the years ended December 31, 2017, 2016 and 2015:
 
Elk Hills
 
Wilmington
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Production data:
 

 
 

 
 

 
 

 
 

 
 

Oil (MBbl/d)
19

 
21

 
24

 
23

 
25

 
28

NGLs (MBbl/d)
13

 
13

 
15

 

 

 

Natural gas (MMcf/d)
95

 
106

 
123

 
1

 

 
1

Average realized prices:(a)
 

 
 

 
 

 
 

 
 

 
 

Oil (MBbl/d)
$
55.58

 
$
44.50

 
$
52.78

 
$
49.87

 
$
37.98

 
$
45.50

NGLs (MBbl/d)
$
36.26

 
$
23.03

 
$
20.12

 
$

 
$

 
$

Natural gas (MMcf/d)
$
2.52

 
$
2.27

 
$
2.67

 
$
2.12

 
$
1.83

 
$
2.05

Production costs per Boe(b)
$
11.76

 
$
10.48

 
$
11.11

 
$
27.91

 
$
22.27

 
$
21.87

Production costs, excluding effects of PSC contracts(c)
N/A
 
N/A
 
N/A
 
$
21.59

 
$
17.21

 
$
17.74

(a)
Excludes the effect of hedges.
(b)
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas to one Bbl of oil.
(c)
The reporting of our PSC-like contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. The amounts represent the production costs for the Company after adjusting for this difference.
The following table sets forth our reserves and production by basin and recovery mechanism:
 
Total Proved Reserves
 
Average Net Daily
Production(MBoe/d)
 
% of Total Basin
 
Oil (%)
 
Year ended
December 31, 2017
San Joaquin Basin
 

 
 

 
 

Primary Conventional
13
%
 
64
%
 
13

Waterfloods
14
%
 
76
%
 
8

Steamfloods(a)
30
%
 
100
%
 
25

Unconventional
43
%
 
33
%
 
44

San Joaquin Basin subtotal(b)
419

 
63
%
 
90

 
 
 
 
 
 
Los Angeles Basin
 

 
 

 
 

Primary Conventional

 
%
 

Waterfloods
100
%
 
99
%
 
27

Steamfloods

 

 

Unconventional

 

 

Los Angeles Basin subtotal(b)
145

 
99
%
 
27

 
 
 
 
 
 
Ventura Basin
 

 
 

 
 

Primary Conventional
35
%
 
80
%
 
3

Waterfloods
65
%
 
86
%
 
3

Steamfloods

 

 

Unconventional

 

 

Ventura Basin subtotal(b)
40

 
85
%
 
6

 
 
 
 
 
 
Sacramento Basin
 

 
 

 
 

Primary Conventional
100
%
 

 
6

Sacramento Basin subtotal(b)
14

 

 
6

 
 
 
 
 
 
Total
618

 
72
%
 
129

(a)
Includes reserves and production from gas injection of 12% and 10%, respectively.
(b)
Subtotal basin reserves in MMBoe.

40



Productive Wells
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. Net wells represent the sum of fractional interests in wells in which we own an interest. Our average working interest in our producing wells is approximately 87%. Wells are categorized based on the primary product they produce.

The following table sets forth our productive oil and natural gas wells (both producing and capable of production) as of December 31, 2017, excluding wells that have been idle for more than five years:
 
As of December 31, 2017
 
Productive Oil Wells
 
Productive Gas Wells
 
Gross(a)
 
Net(b)
 
Gross(a)
 
Net(b)
San Joaquin Basin
8,058

 
6,826

 
162

 
135

Los Angeles Basin
1,629

 
1,579

 
1

 
1

Ventura Basin
819

 
812

 

 

Sacramento Basin

 

 
965

 
886

Total(c)
10,506

 
9,217

 
1,128

 
1,022

Multiple completion wells included above
57

 
54

 
48

 
44

(a)
The total number of wells in which interests are owned.
(b)
Sum of our fractional interests.
(c)
This total represents both producing and capable of producing wells. As of December 31, 2017, we had 2,690 gross (2,455 net) oil wells and 308 gross (283 net) gas wells that are capable of production but currently not producing, and a total of 8,636 gross (7,501 net) producing wells, approximately 91% of which were oil wells.
Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2017, of which approximately 60% is held in fee, 15% is held by production and 25% are term leases.
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
 
(in thousands)
Developed(a)
 

 
 

 
 

 
 

 
 

Gross(b)
417

 
21

 
63

 
267

 
768

Net(c)
379

 
16

 
61

 
247

 
703

Undeveloped(d)
 

 
 

 
 

 
 

 
 

Gross(b)
1,317

 
17

 
224

 
341

 
1,899

Net(c)
1,087

 
14

 
187

 
261

 
1,549

(a)
Acres spaced or assigned to productive wells.
(b)
Total number of acres in which interests are owned.
(c)
Sum of our fractional interests based on working interests or interests under arrangements similar to production-sharing contracts.
(d)
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.
Work programs are designed to ensure that the exploration potential of any leased property is fully evaluated before expiration. In some instances, we may relinquish leased acreage in advance of the contractual expiration date if the evaluation process is complete and there is no longer a commercial reason for leasing that acreage. In cases where we determine we want to take the additional time required to fully evaluate acreage, we have generally been successful in obtaining extensions. The combined net acreage covered by leases expiring in the next three years represents approximately 16% of our total net undeveloped acreage at December 31, 2017 and these expirations would not have a material adverse impact on us. Historically, we have not dedicated any significant portion of our capital program to prevent lease expirations and do not expect we will need to do so in the future.


41



Drilling Activities
The following table sets forth information with respect to our net exploration and development wells completed during the periods indicated. Net wells represent the sum of fractional interests in wells in which we own an interest. 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.
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
2017
 

 
 

 
 

 
 

 
 

Oil
 

 
 

 
 

 
 

 
 

Exploratory
2

 

 

 

 
2

Development
92

 
15

 
2

 

 
109

Dry
 

 
 

 
 

 
 

 


Exploratory
3

 

 

 

 
3

Development

 

 

 

 

 
 
 
 
 
 
 
 
 
 
2016
 

 
 

 
 

 
 

 
 

Oil
 

 
 

 
 

 
 

 
 

Exploratory

 

 

 

 

Development
37

 
5

 

 

 
42

 
 
 
 
 
 
 
 
 
 
2015
 

 
 

 
 

 
 

 
 

Oil
 

 
 

 
 

 
 

 
 

Exploratory
3

 

 

 

 
3

Development
254

 
29

 

 

 
283


The following table sets forth information with respect to our exploration and development wells for which drilling was in progress or pending completion as of December 31, 2017, which are not included in the above table.
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
Exploratory and development wells
 

 
 

 
 

 
 

 
 

Gross(a)
13

 

 
1

 
1

 
15

Net(b)
12

 

 
1

 

 
13

(a)
The total number of wells in which interests are owned.
(b)
Sum of our fractional interests.
On a gross basis, these projects included four primary, six steamfloods, one waterflood and two unconventional wells in the San Joaquin basin, as well as one primary project in each of the Ventura and Sacramento basins.
Delivery Commitments
We have made short-term commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2017, we had oil, natural gas and NGL delivery commitments of 47 MBbl/d, 56 MMcf/d and 18 MBbl/d, respectively, through May 2018. These are index-based contracts with prices set at the time of delivery. We have significantly more production capacity than the amounts committed for oil and natural gas. We have agreements to purchase third-party NGLs for any shortfall between the committed quantities and our production. Further, we have the ability to secure additional volumes for all products if necessary. None of the commitments are expected to have a material impact on our financial statements.


42



Our Infrastructure
We own a network of infrastructure that is integral to and significantly complements our operations. Our significant footprint in California and wide network of infrastructure helps us connect to third-party transportation pipelines, providing us with a competitive advantage by reducing our operating costs. In February 2018, we entered into a midstream JV in which the Ares JV holds the Elk Hills natural gas processing plant and power plant described below. For further information regarding the Ares JV, see Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Joint Ventures.

Our infrastructure includes the following:
Description
 
Quantity
 
Unit(a)
 
Capacity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
San Joaquin Basin
 
Other Basins
 
Total
Gas Plants
 
9
 
MMcf/d
 
610
 
50
 
660
Power Plants/Co-generation
 
3
 
MW
 
600
 
50
 
650
Steam Generators/Plants
 
>50
 
MBbl/d
 
220
 
 
220
Compressors
 
400
 
MHp
 
300
 
20
 
320
Water Management Systems
 
22
 
MBw/d
 
2,400
 
2,100
 
4,500
Water Softeners
 
30
 
MBw/d
 
265
 
 
265
Oil and NGL Storage
 
 
 
MBbls
 
580
 
660
 
1,240
Gathering Systems