10-K 1 a2018ye10-kdocument.htm 10-K 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, 2018
¨    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.)
 
 
 
27200 Tourney Road, Suite 315
Santa Clarita, California
(Address of principal executive offices)
 
91355
(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 every Interactive Date File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period as the registrant was required to submit such 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.   þ
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
þ
Accelerated Filer
¨
Non-Accelerated Filer
¨
Smaller Reporting Company
¨
Emerging Growth Company
¨
 
 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant 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 $2.2 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $45.44 per share of Common Stock on June 30, 2018. 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, 2019, there were 48,650,420 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 2019 Annual Meeting of Stockholders, are incorporated by reference into Part III of this Form 10-K.



TABLE OF CONTENTS
 
 
Page
Part I
 
 
Items 1 & 2
BUSINESS AND PROPERTIES
 
Business Operations and Environment
 
Our Business Strategy
 
Our Strengths
 
Our Operations
 
Acreage
 
Production, Price and Cost History
 
Reserves
 
Recovery Mechanisms
 
Drilling Locations
 
Drilling Statistics
 
Productive Wells
 
Exploration Program
 
Marketing Arrangements
 
Infrastructure
 
Employees
 
Regulation of the Oil and Natural Gas Industry
 
Spin-Off and Reverse Stock Split
 
Available Information
Item 1A
RISK FACTORS
Item 1B
UNRESOLVED STAFF COMMENTS
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
 
Acquisitions and Divestitures
 
Income Taxes
 
Production and Prices
 
Balance Sheet Analysis
 
Statement of Operations Analysis
 
Liquidity and Capital Resources
 
2018 and 2019 Capital Program
 
Off-Balance-Sheet Arrangements
 
Lawsuits, Claims, Commitments and Contingencies
 
Critical Accounting Policies and Estimates
 
Significant Accounting and Disclosure Changes
 
FORWARD-LOOKING STATEMENTS
Item 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

2



 
 
Page
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

ITEMS 1 & 2
BUSINESS AND PROPERTIES

Business Operations and Environment

We are an independent oil and natural gas exploration and production company operating properties exclusively within the state of California. We are the largest oil and gas producer in California on a gross operated basis, with average net daily production of 132 thousand of barrels of oil equivalent per day (MBoe/d) in 2018. We have the largest privately held mineral acreage position in the state, consisting of approximately 2.2 million net mineral acres spanning four of California's major oil and gas basins. Our proved reserves totaled an estimated 712 million barrels of oil equivalent (MMBoe) at December 31, 2018.
We have a diversified portfolio of oil and natural gas locations and extensive drilling inventory that are economically viable in a variety of operating and commodity price conditions, including many that are high-value projects throughout the commodity price cycle. Our acreage position contains numerous development and growth opportunities due to its varied geologic characteristics and multiple stacked-pay reservoirs that are, in many cases, thousands of feet thick. Our returns are enhanced relative to our peers because we do not make royalty or other lease payments on over 60% of our acreage, which is held in fee.
Our large portfolio of low-risk and low-decline conventional opportunities spans each of our oil and gas basins and comprises approximately 72% of our proved reserves. We are in various phases of developing many of our conventional assets and will continue to develop them by using internally generated cash flow and, when appropriate, raising capital through joint ventures (JVs).

We also own or control a network of strategically placed infrastructure that is integrated with, and complementary to, our operations, including gas plants, oil and gas gathering systems, power plants and other related assets, which we use to maximize the value generated from our production.

Our 3D seismic library covers approximately 4,860 square miles, representing approximately 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. We have successfully implemented various exploration, drilling, completion and enhanced recovery technologies to increase recoveries, growth and value from our portfolio.
We were formed in April 2014 and are currently listed on the New York Stock Exchange. All references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.
Our Business Strategy

We provide ample, affordable and reliable energy, in a safe and responsible manner, to support and enhance the quality of life for Californians and the local communities where we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to providing value. Our long-term value-driven growth strategy is focused on five key priorities:

Utilize our technical knowledge and experience to target production growth, delineate expansion areas and optimize hydrocarbon recovery;
Use our Value Creation Index (VCI) metric to ensure consistent, disciplined and effective capital allocation;
Optimize operational performance through streamlined processes, application of technology and entrepreneurial thinking to capture efficiencies, improve results and reduce costs;
Strengthen our balance sheet by investing to grow cash flow, simplifying our capital structure, pursuing value-accretive acquisitions and reducing absolute levels of our debt and fixed charges; and
Maintain a proactive and collaborative approach to safety, environmental protection and community outreach while helping California address its energy and water needs.


4



Our Strengths

The following characteristics position us to successfully execute our business strategy:

Operational control and a diverse asset base provide us with flexibility.

We have ownership or operational control over substantially all of our assets. This allows us to adapt our investments by selecting drilling locations, timing the development and the drilling and completion techniques used and allocating capital in a manner designed to optimize cash flow over a wide range of commodity prices.

We have a large and diverse mineral acreage position that permits a variety of recovery mechanisms and product types. The majority of our interests are in producing properties located in reservoirs that we believe have long-lived production profiles with repeatable development opportunities. The low base decline of our conventional assets allows us to limit production declines with minimal investment.

With our significant land holdings in California, we have undertaken new initiatives to unlock additional value from our real estate. Our real estate development initiatives include exploring renewable energy opportunities on our land such as solar energy projects, agricultural activities (such as the production of fruits and nuts) and other commercial uses. We are also exploring carbon dioxide capture and storage projects and reclaimed water opportunities.

Largest acreage position in a world-class oil and natural gas province.

Our operations are located exclusively in California, which is one of the most prolific oil and natural gas producing regions in the world and is currently the sixth largest oil producing state in the nation. According to the California Department of Conservation, Division of Oil, Gas, and Geothermal Resources' (DOGGR) information through 2017, 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, in the San Joaquin basin, is the second largest oil producing county in the lower 48 states. California is also the nation’s largest state economy, and the world's fifth largest, with significant energy demands that exceed local supply. Our large acreage position and diverse development portfolio enable us to pursue the appropriate production strategy for the relevant commodity price environment without the need to acquire new acreage and allow us to quickly deploy the knowledge we gain in our existing operations, together with our seismic data, to other areas within our portfolio.

Extensive drilling and workover portfolio.

Our drilling inventory at December 31, 2018 consisted of approximately 32,350 gross (25,090 net) identified well locations, of which approximately 95% are oil. In addition, we continue to maintain our available workover projects that can deliver high returns. Our inventory of largely lower-risk conventional development opportunities has increased more than our unconventional opportunities. In a sustained favorable oil and gas price environment, we believe we can achieve further long-term production growth through the development of unconventional reservoirs. In addition, our large 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.

5



Our Operations
The following table highlights key information about our operations as of and for the year ended December 31, 2018 in each of California's four major oil and gas basins:
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total Operations
Acreage:
 
 
 
 
 
 
 
 
 
Net mineral acreage (thousands)
1,446

 
30

 
247

 
517

 
2,240

Average net mineral acreage held in fee (%)
66
%
 
46
%
 
74
%
 
38
%
 
60
%
 
 
 
 
 
 
 
 
 
 
Number of fields
49

 
8

 
27

 
53

 
137

Average net revenue interest (%)(a)
90
%
 
73
%
 
83
%
 
78
%
 
86
%
Average drilling rigs
7

 
3

 

 

 
10

Net wells drilled and completed
128.6

 
48.2

 
3.5

 

 
180.3

 
 
 
 
 
 
 
 
 
 
Proved reserves:
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
317

 
173

 
40

 

 
530

NGLs (MMBbl)
57

 

 
3

 

 
60

Natural Gas (Bcf)
621

 
13

 
32

 
68

 
734

Total (MMBoe)
478

 
175

 
48

 
11

 
712

Oil percentage of proved reserves
66
%
 
99
%
 
83
%
 
%
 
74
%
 
 
 
 
 
 
 
 
 
 
Production:
 
 
 
 
 
 
 
 
 
Total (MMBoe)
35

 
9

 
2

 
2

 
48

Average net daily production (MBoe/d)
96

 
25

 
6

 
5

 
132

Oil percentage of production
55
%
 
100
%
 
67
%
 
%
 
62
%
 
 
 
 
 
 
 
 
 
 
Reserves to production ratio (years)(b)
13.7

 
19.4

 
24.0

 
5.5

 
14.8

Note: MMBbl refers to millions of barrels; Bcf refers to billions of cubic feet; MMBoe refers to millions of barrels of oil equivalent; and MBoe/d refers to thousands of barrels of oil equivalent per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(a)
The average net revenue interest represents our interest in production after taking into account royalties and similar burdens and third- party working interests.
(b)
Calculated as total proved reserves as of December 31, 2018 divided by total production for the year ended December 31, 2018.
San Joaquin Basin
According to the 2012 U.S. Geological Survey, the San Joaquin basin contained three of the 10 largest oil fields in the United States based on cumulative production and proved reserves. Commercial petroleum development in the basin began in the 1800s. The basin contains multiple stacked formations throughout its areal extent, and we believe that the San Joaquin basin provides appealing opportunities for field re-development of existing wells, as well as new discoveries and unconventional play potential. The complex geology in the San Joaquin basin has allowed continuing discoveries of stratigraphic and structural traps. Approximately 75% of California’s total daily oil production for 2017 was produced in the San Joaquin basin, according to DOGGR.
The Elk Hills field is our largest producing asset and has been one of the largest fields in the continental U.S. based on proved reserves. Following the acquisition of Chevron's interest in April 2018, we now hold all of the working, surface and mineral interests in the former Elk Hills unit.
At Elk Hills we also operate efficient natural gas processing facilities, including a state-of-the-art cryogenic gas plant, with a combined gas processing capacity of over 520 MMcf/d. Additionally, the Elk Hills power plant generates sufficient electricity to operate the field, and sells excess power to the grid and to a utility. Our operations at Elk Hills also include an advanced central control facility and remote automation control on over 95% of our producing wells.

6



We believe our extensive 3D seismic library, which covers over 880,000 acres in the San Joaquin basin, or approximately 50% of our gross acreage in this basin, will give us a competitive advantage in further exploration. We have established a large ownership interest in several of the largest existing oil fields in the San Joaquin basin, including Elk Hills, Buena Vista and Kettleman North Dome. We have also been successfully developing steamfloods in our Kern Front operations and in the northwest portion of the Lost Hills field.
Los Angeles Basin
This basin is a northwest-trending plain about 50 miles long and 20 miles wide. Most of the significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has one of the highest concentrations per acre of crude oil in the world 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.
The Wilmington field has been one of the largest fields in the continental U.S. based on proved reserves. Most of our Wilmington production is subject to a set of contracts similar to production-sharing contracts (PSCs) 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.
Ventura Basin
The Ventura Basin is the oldest operating petroleum basin in California extending from northern Los Angeles County to the coastal city of Ventura and continues offshore encompassing the Santa Barbara channel. The earliest discoveries were mines dug into hillsides to mine active oil seeps. The first commercial oil well started in 1866. All of the sedimentary section is productive at various locations, and most reservoirs are sandstones with favorable porosity and permeability. As of December 31, 2018, we operated more than 20 oilfields in this historic and prolific basin. The basin contains multiple stacked formations throughout its depths and provides an appealing inventory of existing field re-development opportunities, as well as new exploration potential. We continue to explore over 10,000 feet of proven stacked oil reservoirs throughout the basin.
Sacramento Basin
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. 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.
Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we held an interest as of December 31, 2018. Approximately 60% of our total net mineral interest position is held in fee, approximately 16% is held by production and the remainder is subject to term leases.
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
 
(in thousands)
Developed(a)
 

 
 

 
 

 
 

 
 

Gross(b)
417

 
21

 
63

 
266

 
767

Net(c)
378

 
16

 
61

 
246

 
701

Undeveloped(d)
 

 
 

 
 

 
 

 
 

Gross(b)
1,297

 
17

 
222

 
355

 
1,891

Net(c)
1,068

 
14

 
186

 
271

 
1,539

Total
 
 
 
 
 
 
 
 
 
Gross(b)
1,714

 
38

 
285

 
621

 
2,658

Net(c)
1,446

 
30

 
247

 
517

 
2,240

(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 PSC-type 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.

7



Our oil and gas leases have primary terms ranging from one to ten years. Once production commences, the leases are extended through the end of their producing life.
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 undeveloped acreage, we have generally been successful in obtaining extensions. The combined net acreage covered by leases expiring in the next three years represented approximately 14% of our total net undeveloped acreage at December 31, 2018 and these expirations, should they occur, would not have a material adverse impact on us. Historically, we have not dedicated any significant portion of our capital program to prevent lease expirations and do not expect we will need to do so in the future.
Production, Price and Cost History
Oil, NGLs and natural gas are commodities, and the price 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 domestic and global supply and demand; domestic and global inventory levels; political and economic conditions; the actions of OPEC and other significant producers and governments; changes or disruptions in actual or anticipated production, refining and processing; worldwide drilling and exploration activities; government energy policies and regulations, including with respect to climate change; the effects of conservation; weather conditions and other seasonal impacts; speculative trading in derivative contracts; currency exchange rates; technological advances; transportation and storage capacity, bottlenecks and costs in producing areas; the price, availability and acceptance of alternative energy sources; regional market conditions and other matters affecting the supply and demand dynamics for these products. 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.
Our production costs include variable costs that fluctuate with 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. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. 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 minimize 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.

Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to PSCs that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and production costs. We record a share of production and reserves to recover a portion of such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and production costs that we incur on their behalf, (ii) for our share of contractually defined base production, and (iii) for our share of remaining production thereafter. We recover our share of capital and production costs, and generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and production costs. However, our net economic benefit is greater when product prices are higher. The contracts represented 15% of our production for the year ended December 31, 2018.


8



In addition, in line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts. This difference in reporting full operating costs but only our net share of production equally inflates our revenue and operating costs per barrel and has no effect on our net results.

The following table sets forth information regarding our production, realized and benchmark prices, and production costs per Boe for the years ended December 31, 2018, 2017 and 2016. 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,
 
2018
 
2017
 
2016
Average net daily production:
 

 
 

 
 

Oil (MBbl/d)(a)
82

 
83

 
91

NGLs (MBbl/d)
16

 
16

 
16

Natural gas (MMcf/d)
202

 
182

 
197

Total net production (MBoe/d)(b)
132

 
129

 
140

 
 
 
 
 
 
Total production (MMBoe)(a)(b)
48

 
47

 
51

 
 
 
 
 
 
Average realized prices:
 

 
 

 
 

Oil prices with hedge ($/Bbl)
$
62.60

 
$
51.24

 
$
42.01

Oil prices without hedge ($/Bbl)
$
70.11

 
$
51.47

 
$
39.72

NGLs prices ($/Bbl)
$
43.67

 
$
35.76

 
$
22.39

Natural gas prices ($/Mcf)
$
3.00

 
$
2.67

 
$
2.28

 
 
 
 
 
 
Average benchmark prices:
 

 
 

 
 

Brent oil ($/Bbl)
$
71.53

 
$
54.82

 
$
45.04

WTI oil ($/Bbl)
$
64.77

 
$
50.95

 
$
43.32

NYMEX gas ($/MMBtu)
$
2.97

 
$
3.09

 
$
2.42

 
 
 
 
 
 
Average production costs per Boe(b):
 

 
 

 
 

Production costs
$
18.88

 
$
18.64

 
$
15.61

Production costs, excluding effects of PSC-type contracts(c)
$
17.47

 
$
17.48

 
$
14.69

Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MMBtu refers to Million British Thermal Units.
(a)
Our PSC-type contracts negatively impacted our oil production in 2018 by over 1 MBoe/d compared to 2017. The impact on our oil production was immaterial in 2017 compared to 2016.
(b)
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas (Mcf) to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(c)
The reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. These amounts represent production costs after adjusting for the excess costs attributable to PSC-type contracts.

9




The following table sets forth information regarding production, realized prices and production costs per Boe for our two largest fields, Elk Hills and Wilmington, for the years ended December 31, 2018, 2017 and 2016:
 
Elk Hills
 
Wilmington
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Average net production:
 

 
 

 
 

 
 

 
 

 
 

Oil (MBbl/d)
22

 
19

 
21

 
21

 
23

 
25

NGLs (MBbl/d)
12

 
13

 
13

 

 

 

Natural gas (MMcf/d)
108

 
95

 
106

 
1

 
1

 

Total net production (MBoe/d)
52

 
48

 
52

 
21

 
23

 
25

Average realized prices(a):
 

 
 

 
 

 
 

 
 

 
 

Oil (MBbl/d)
$
73.98

 
$
55.58

 
$
44.50

 
$
67.81

 
$
49.87

 
$
37.98

NGLs (MBbl/d)
$
43.58

 
$
36.26

 
$
23.03

 
$

 
$

 
$

Natural gas (MMcf/d)
$
2.87

 
$
2.52

 
$
2.27

 
$
1.71

 
$
2.12

 
$
1.83

Production costs per Boe(b)
$
12.07

 
$
11.76

 
$
10.48

 
$
29.81

 
$
27.91

 
$
22.27

Production costs per Boe, excluding effects of PSC-type contracts(c)
N/A
 
N/A
 
N/A
 
$
21.02

 
$
21.59

 
$
17.21

(a)
Excludes the effect of hedges.
(b)
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(c)
The reporting of our PSC-type 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. These amounts represent production costs after adjusting for the excess costs attributable to PSC-type contracts.
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 Price), 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 our 2018 reserves estimates, the average benchmark Brent oil price was $71.75 per barrel and the average NYMEX gas price was $3.10 per MMBtu. The average realized prices used for our 2018 reserves were $70.92 per barrel for oil, $43.88 per barrel for NGLs and $2.95 per Mcf for natural gas.

10



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, 2018. Estimated reserves include our economic interests under arrangements similar to PSCs at our Wilmington field in Long Beach.
 
As of December 31, 2018
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
Proved developed reserves:
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
231

 
131

 
27

 

 
389

NGLs (MMBbl)
45

 

 
2

 

 
47

Natural Gas (Bcf)
473

 
9

 
23

 
60

 
565

Total (MMBoe)(a)(b)
355

 
132

 
33

 
10

 
530

 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
86

 
42

 
13

 

 
141

NGLs (MMBbl)
12

 

 
1

 

 
13

Natural Gas (Bcf)
148

 
4

 
9

 
8

 
169

Total (MMBoe)(b)
123

 
43

 
15

 
1

 
182

 
 
 
 
 
 
 
 
 
 
Total proved reserves:
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
317

 
173

 
40

 

 
530

NGLs (MMBbl)
57

 

 
3

 

 
60

Natural Gas (Bcf)
621

 
13

 
32

 
68

 
734

Total (MMBoe)(b)
478

 
175

 
48

 
11

 
712

(a)
As of December 31, 2018, approximately 23% of proved developed oil reserves, 9% of proved developed NGLs reserves, 13% of proved developed natural gas reserves and, overall, 20% 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 of six thousand cubic feet of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

Proved Reserves Additions

The components of the changes to our proved reserves during the year ended December 31, 2018 were as follows (in MMBoe):
 
San Joaquin Basin
 
Los Angeles Basin(a)
 
Ventura Basin
 
Sacramento Basin
 
Total
Balance at December 31, 2017
419

 
145

 
40

 
14

 
618

Revisions related to price
16

 
23

 
1

 
(2
)
 
38

Revisions related to performance
(8
)
 
8

 
5

 
1

 
6

Improved recovery
4

 

 

 

 
4

Extensions and discoveries
18

 
8

 
4

 

 
30

Purchases
64

 

 

 

 
64

Sales

 

 

 

 

Production
(35
)
 
(9
)
 
(2
)
 
(2
)
 
(48
)
Balance at December 31, 2018
478

 
175

 
48

 
11

 
712

Note:
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(a)
Includes proved reserves related to PSC-type contracts of 131 MMBoe and 108 MMBoe at December 31, 2018 and 2017, respectively.
In 2018, total net additions to proved reserves from all sources were 142 MMBoe. Our 2018 realized prices for oil and natural gas increased over the prior year by 39% and 14%, respectively, which resulted in positive price-related revisions of 38 MMBoe.

11



We added 6 MMBoe from net positive performance-related revisions of which 27 MMBoe were from positive technical revisions due to better-than-expected performance and successful drilling efforts in the San Joaquin and Los Angeles basins. These additions were partially offset by 21 MMBoe of negative revisions due to management's discretion to downgrade proved undeveloped reserves (PUDs) that are not anticipated to be developed within their five-year window of initial booking. Approximately 11 MMBoe of these downgraded PUDs are expiring in 2019 and are not anticipated to be developed before then at current oil prices. The remaining 10 MMBoe of downgraded PUDs are projects that are no longer prioritized in our development plan based on current project economics.

We also added 4 MMBoe from improved recovery through proven IOR and EOR methods. The improved recovery additions were associated with the continued development of steamflood and waterflood properties in the San Joaquin basin.

We added 30 MMBoe from extensions and discoveries, primarily resulting from new geologic interpretations and pressure data in the Ventura basin along with successful drilling in the San Joaquin and Los Angeles basins.

We also added 64 MMBoe in connection with acquisitions during the year, the majority of which resulted from the Elk Hills transaction.

Excluding PUD downgrades of 21 MMBoe that were made at management's discretion, we achieved an organic reserve replacement ratio of 127% from our capital program of $690 million. Additionally, our JV partner MIRA funded $57 million, which contributed to our reserve adds. Our total net reserve additions from all sources generated a reserve replacement ratio of 296%. For further information on our reserve replacement ratio, see the PV-10, Standardized Measure and Reserve Replacement Ratio section below.

See Item 8 – Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for further discussion of changes in our proved reserves.

Proved Undeveloped Reserves

The total changes to our PUDs during the year ended December 31, 2018 were as follows (in MMBoe):
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
Balance at December 31, 2017
125

 
40

 
11

 
2

 
178

Revisions related to performance
(15
)
 
1

 
4

 

 
(10
)
Revisions related to price changes
2

 
2

 
(4
)
 
(1
)
 
(1
)
Extensions and discoveries
12

 
5

 
4

 

 
21

Improved recovery
3

 

 

 

 
3

Purchases
17

 

 

 

 
17

Transfers to proved developed reserves
(21
)
 
(5
)
 

 

 
(26
)
Balance at December 31, 2018
123

 
43

 
15

 
1

 
182

Note:
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

In 2018, we had net negative performance-related revisions of 10 MMBoe, reflecting a 21 MMBoe downward adjustment based on management discretion as described above, which was partially offset by 11 MMBoe of positive revisions.

We added 21 MMBoe of PUDs through extensions and discoveries, primarily resulting from new geologic interpretations and pressure data in the Ventura basin along with successful drilling in the San Joaquin and Los Angeles basins.

We added proved reserves of 3 MMBoe from improved recovery through proven IOR and EOR methods. The improved recovery additions were associated with the continued development of steamflood and waterflood properties in the San Joaquin basin. Approximately 79% of the PUD additions from extensions and discoveries and improved recovery were crude oil.


12



We transferred 26 MMBoe of PUDs to the proved developed category as a result of the 2018 capital program, all of which was in the San Joaquin and Los Angeles basins. As a result, we converted approximately 15% of our beginning-of-year PUDs to proved developed reserves during the year, investing approximately $235 million of development capital.

Our year-end development plans and associated PUDs are consistent with SEC guidelines for development within five years. We believe we will have sufficient capital to develop all year-end 2018 PUDs within five years of their original booking date. Management's capital commitment assumes an average $65 Brent price for 2019 and approximately $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 average future price remained at $65 Brent, our PUDs would be reduced by approximately 5 to 10% over the long term.

PV-10, Standardized Measure and Reserve Replacement Ratio

As of December 31, 2018, our standardized measure of discounted future net cash flows (Standardized Measure) was $7.3 billion and PV-10 was approximately $9.4 billion. In addition, we organically replaced 127% of our proved reserves in 2018, excluding the effect of PUDs downgraded at management's discretion.

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, 2018
 
(in millions)
Standardized measure of discounted future net cash flows
$
7,275

Present value of future income taxes discounted at 10%
2,136

PV-10 of proved reserves
$
9,411

Organic reserve replacement ratio(a)
127
%
All-in reserve replacement ratio(b)
296
%
(a)
The organic reserve replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery and performance-related revisions (excluding 21 MMBoe of PUDs downgraded at management's discretion), 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.
(b)
The all-in reserve replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery, revisions and purchases, 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.


13



Reserves Evaluation and Review Process

Our estimates of proved reserves and associated discounted future net cash flows as of December 31, 2018 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 2018. The Reserves Committee reports its findings to the Audit Committee during the year.

Audits of Reserves Estimates

Ryder Scott was engaged to provide an independent audit of our reserves estimates for fields that comprised at least 80% of our total proved reserves. The primary technical engineer responsible for our audit has 39 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 2018 reserves audit covered over 80% of our total proved reserves. Over 95% of our total 2018 proved reserves were audited by Ryder Scott at some time during 2015 through 2018. 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.


14



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 as of December 31, 2018. Ryder Scott's report is attached as an exhibit to this Form 10-K.
Recovery Mechanisms
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
 
Year ended
December 31, 2018
San Joaquin Basin
 

 
 

Primary
15
%
 
15

Waterfloods
13
%
 
9

Steamfloods
31
%
 
24

Unconventional
41
%
 
48

San Joaquin Basin subtotal(a)
478

 
96

 
 
 
 
Los Angeles Basin
 

 
 

Waterfloods
100
%
 
25

Los Angeles Basin subtotal(a)
175

 
25

 
 
 
 
Ventura Basin
 

 
 

Primary
34
%
 
3

Waterfloods
66
%
 
3

Ventura Basin subtotal(a)
48

 
6

 
 
 
 
Sacramento Basin
 

 
 

Primary
100
%
 
5

Sacramento Basin subtotal(a)
11

 
5

 
 
 
 
Total
712

 
132

(a)
Subtotal basin reserves in MMBoe. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

Conventional Reservoirs

Conventional reservoirs are capable of natural flow during primary recovery phase, often followed by waterflood and steamflood recovery methods to enhance ultimate recovery. 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 using primary recovery methods, followed by secondary techniques such as Improved Oil Recovery (IOR) methods like waterflooding and Enhanced Oil Recovery (EOR) methods like steamflooding, both of which use vertical and horizontal drilling. All of these techniques are well understood technologies that we have used extensively in California.

15




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 conventional reservoir. Our successful exploration program continues to provide us with primary recovery opportunities in new reservoirs or through extensions of existing fields. Our primary recovery programs create future opportunities to convert these reservoirs to waterfloods or steamfloods after their primary production phase.

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. 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.

Steamfloods

Some of our fields contain heavy, thick oil. Steamfloods work by injecting steam into the reservoir to heat the oil which allows 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 generally requires 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 as gas is used to generate steam production. 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 production.

Unconventional Reservoirs

We have a significant portfolio of lower permeability unconventional reservoirs that typically utilize established well-stimulation techniques. 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 acres with unconventional potential and have identified 4,620 (gross and net) unconventional drilling locations on this acreage, excluding unconventional exploration drilling locations. Approximately 36% of our 2018 production was from unconventional reservoirs, all in the San Joaquin basin. Our unconventional production from our largest field, the Elk Hills field in the San Joaquin basin, increased approximately 10% in 2018 from the prior year. As of December 31, 2018, we had proved reserves of approximately 196 MMBoe associated with our unconventional properties, approximately 25% of which were proved undeveloped reserves.

We hold significant interests in the Monterey formation, which is divided into upper and lower intervals. Prior to the severe price declines that began in late 2014, we were focused on developing higher-value unconventional production from seven discrete stacked pay horizons within the Monterey formation, primarily within the upper Monterey. In 2018, 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. During the year ended December 31, 2018, we had unconventional production of approximately 47 MBoe/d on average from the upper Monterey in the San Joaquin basin.

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. However, over the long term, we believe we will be able to apply knowledge we gain from the upper Monterey to the lower Monterey, Kreyenhagen and Moreno formations, which have similar geological attributes.

16




Drilling Locations
The table below sets forth our total gross identified drilling locations as of December 31, 2018, excluding our unconventional exploration drilling locations.
 
Proven Drilling Locations
 
Total Identified Drilling Locations(a)
 
Oil and
Natural Gas Wells
 
Injection Wells
 
Oil and
Natural Gas Wells
 
Injection Wells
San Joaquin Basin
 

 
 

 
 

 
 

Primary Conventional
140

 

 
8,080

 

Steamflood
570

 
150

 
8,350

 
450

Waterflood
90

 
40

 
1,970

 
980

Unconventional
220

 

 
4,520

 

San Joaquin Basin subtotal
1,020

 
190

 
22,920

 
1,430

 
 
 
 
 
 
 
 
Los Angeles Basin
 

 
 

 
 

 
 

Waterflood
460

 
130

 
1,520

 
500

Los Angeles Basin subtotal
460

 
130

 
1,520

 
500

 
 
 
 
 
 
 
 
Ventura Basin
 

 
 

 
 

 
 

Primary Conventional
30

 

 
1,400

 

Steamflood

 

 
120

 

Waterflood
80

 
60

 
1,560

 
520

Unconventional

 

 
100

 

Ventura Basin subtotal
110

 
60

 
3,180

 
520

 
 
 
 
 
 
 
 
Sacramento Basin
 

 
 

 
 

 
 

Primary Conventional
10

 

 
2,280

 

Sacramento Basin subtotal
10

 

 
2,280

 

 
 
 
 
 
 
 
 
Total Drilling Locations
1,600

 
380

 
29,900

 
2,450

(a)
Total gross identified drilling locations is comprised of gross proven drilling locations of 1,980 gross (1,970 net), gross unproven drilling locations of 17,030 gross (16,870 net) and gross conventional exploration drilling locations of 13,340 gross (6,250 net). Total gross identified drilling locations excludes gross unconventional exploration drilling locations of 6,400 gross (5,300 net).

Proven Drilling Locations

Based on our reserves report as of December 31, 2018, we have approximately 1,980 gross (1,970 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 reserves 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.

17




Unproven Drilling Locations

We have also identified a multi-year inventory of 17,030 gross (16,870 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 13,340 gross (6,250 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 analog data, 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.

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 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.

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 steamflood). Due to the significant vertical thickness and multiple stacked reservoirs, 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 are either included in our drilling schedule or are expected to be scheduled in the future. When we identify these locations, we make assumptions about the consistency and accuracy of data that may prove inaccurate. For a discussion of the risks associated with our drilling program, see Item 1A – Risk Factors – Risks Related to Our Business and Industry.

18



Drilling Statistics

The following table sets forth information on our net exploration and development oil wells completed during the periods indicated, regardless of when drilling was initiated. We did not drill any gas wells in 2018. 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 Net Wells
2018
 

 
 

 
 

 
 

 
 

Productive
 

 
 

 
 

 
 

 
 

Exploratory
0.3

 

 

 

 
0.3

Development
127.0

 
48.2

 
3.2

 

 
178.4

Dry
 

 
 

 
 

 
 

 


Exploratory
1.3

 

 
0.3

 

 
1.6

Development

 

 

 

 

 
 
 
 
 
 
 
 
 
 
2017
 

 
 

 
 

 
 

 
 

Productive
 

 
 

 
 

 
 

 
 

Exploratory
2.0

 

 

 

 
2.0

Development
91.8

 
14.5

 
1.6

 

 
107.9

Dry
 

 
 

 
 

 
 

 
 
Exploratory
3.0

 

 

 

 
3.0

Development

 

 

 

 

 
 
 
 
 
 
 
 
 
 
2016
 

 
 

 
 

 
 

 
 

Productive
 

 
 

 
 

 
 

 
 

Exploratory

 

 

 

 

Development
37.0

 
5.4

 

 

 
42.4


The following table sets forth information on our exploration and development wells where drilling was either in progress or pending completion as of December 31, 2018, which is not included in the above table.
 
San Joaquin Basin
 
Los Angeles Basin
 
Ventura Basin
 
Sacramento Basin
 
Total
Exploratory and development wells
 

 
 

 
 

 
 

 
 

Gross(a)
14.0

 
2.0

 
3.3

 

 
19.3

Net(b)
13.9

 
1.9

 
2.3

 

 
18.1

(a)
The total number of wells in which interests are owned.
(b)
Sum of our fractional interests.
On a gross basis, these projects included three primary, five steamflood, ten waterflood and one unconventional.
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. Our average working interest in our producing wells is approximately 94%. Wells are categorized based on the primary product they produce.


19



The following table sets forth our productive oil and natural gas wells (both producing and capable of production) as of December 31, 2018, excluding wells that have been idle for more than five years:
 
As of December 31, 2018
 
Productive Oil Wells
 
Productive Gas Wells
 
Gross(a)
 
Net(b)
 
Gross(a)
 
Net(b)
San Joaquin Basin
8,419

 
7,961

 
166

 
161

Los Angeles Basin
1,533

 
1,486

 
1

 
1

Ventura Basin
1,320

 
1,312

 

 

Sacramento Basin

 

 
1,012

 
930

Total
11,272

 
10,759

 
1,179

 
1,092

Multiple completion wells included in the total above
382

 
356

 
46

 
42

(a)
The total number of wells in which interests are owned.
(b)
Sum of our fractional interests.

Exploration Program

We have an active exploration program in both conventional and unconventional plays. We believe our experienced technical staff, proprietary geological models, acreage position and extensive 3D seismic library give us a strong competitive advantage. California basins have generated billions of barrels of oil and billions of cubic feet of natural gas 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 reservoirs in each of California's four major oil and gas basins.

Our exploration program is designed to extend fields and add new trends and resource plays to our already broad portfolio, targeting new oil and gas accumulations and leveraging our existing infrastructure. We continue to focus on growing our exploration drilling locations and resource identification, in some cases working with JV partners, primarily in the San Joaquin, Sacramento and Ventura Basins. We have a ranked near-field portfolio of over 150 exploration prospects across the San Joaquin, Sacramento and Ventura basins.

We have executed a deliberate approach to fund a portion of our exploration program through farmouts and joint ventures allowing us to test multiple prospects for minimal net investment. Generally, our JV partners fund the drilling activity in an exploration area on a promoted basis with any future development wells funded in proportion to the respective working interest percentages.

Marketing Arrangements

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, the demand for oil and natural gas in California remains strong. California is heavily reliant on imported sources of energy, with approximately 74% of oil and 90% of natural gas consumed in 2018 imported from outside the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices. We believe that the limited crude transportation infrastructure from other parts of the U.S. into California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades. Additionally, our differentials improved against Brent during 2017 and 2018 in response to strong demand for California crude oil to optimize local refinery yields as well as a decline in overall California crude oil production.

Crude Oil – Substantially all of our crude oil production is connected to third-party pipelines and California markets via our gathering pipelines, which are used almost entirely for our production. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements. We 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. Currently, our index-based crude oil sales contracts have 30-day to nine-month terms with no such contracts extending past one year.


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Natural Gas – We sell all of our natural gas to the California market. 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 60% 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 Elk Hills and other nearby fields, which reduces operating costs and increases reliability. We sell the excess electricity generated to the grid and a local utility. The power sold to the utility is subject to an agreement expiring at the end of 2020, which includes a minimum capacity payment.

Delivery Commitments

We have short-term commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2018, we had oil and NGL delivery commitments of 41 and 19 MBbl/d through March 2019, respectively, and natural gas commitments of 35 MMcf/d through the end of 2019. We have significantly more production capacity than the amounts committed for oil and natural gas. For NGL commitments, we have agreements to cash settle any shortfall between the committed quantities and our production. Further, we have the ability to secure additional volumes of all products if necessary. None of the commitments are expected to have a material impact on our financial statements. These are index-based contracts with prices set at the time of delivery.

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 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.

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 year ended December 31, 2018, our principal customers, Phillips 66 Company and Valero Marketing & Supply Company, each accounted for at least 10%, and, collectively, 43% of our revenue. For the years ended December 31, 2017 and 2016, our principal customers, 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.

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 tax obligations or duties under applicable laws, development obligations, or net profits interests, among other items. Prior to the commencement of drilling operations on those properties, we typically conduct a more thorough title examination and may perform curative work with respect to significant defects. We generally will not commence drilling operations on a property until we have cured known title defects that are material to the project. In addition, substantially all of our properties have been pledged as collateral for our secured debt.


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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 pipelines and only limited rail access and unloading capacity for refineries. As a result, 74% of the oil the state consumes is imported, virtually all from waterborne sources. Our proximity to the California refineries gives us a competitive advantage through lower transportation costs. Further, California refineries are generally designed to process crude with similar characteristics to the oil produced from our fields. The California natural gas market is serviced from a network of pipelines, including interstate and intrastate pipelines. We deliver our natural gas to customers using 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. As oil prices and activity increased in 2017, 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 in 2017 and 2018 due to excess capacity in the service and supply sectors. At current commodity price levels, we expect limited cost inflation to continue in 2019. Given our relative size compared to other in-state producers, our activity level influences the pricing of third-party services in the local market.
Infrastructure
We own a network of infrastructure that is integral to and complements our operations. Our significant footprint in California and wide network of infrastructure help us connect to third-party transportation pipelines, providing us with a competitive advantage by reducing our operating costs.

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
 
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
 
 
 
Miles
 
 
 
 
 
>20,000
(a)
MW refers to megawatts of power; MBbl/d refers to thousand barrels of steam per day; MHp refers to thousand horsepower; MBw/d refers to thousand barrels of water per day; MBbl refers to thousands of barrels.

Gas Processing

We believe we own the largest gas processing system in California. In the San Joaquin basin, the Elk Hills cryogenic gas plant has a capacity of 200 MMcf/d of inlet gas, bringing our total processing capacity in the basin to over 610 MMcf/d. We also own and operate a system of natural gas processing facilities in the Ventura basin that are capable of processing our equity and third-party wellhead gas from the surrounding areas. Our natural gas processing facilities are interconnected via pipelines to nearby third-party rail and trucking facilities, with access to various North American NGL markets. In addition, we have truck rack facilities coupled with a battery of pressurized storage tanks at the Elk Hills natural gas processing facility for NGL sales to third parties.


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Electricity

The 550-megawatt combined-cycle Elk Hills power plant, located adjacent to the Elk Hills gas processing facility, generates all the electricity needs for our Elk Hills and certain contiguous operations in the San Joaquin basin. We utilize approximately a third of its capacity for our operations and our subsidiary sells the excess to the grid and to a local utility. The Elk Hills power plant also provides primary steam supply to our cryogenic gas plant. We also operate, as needed, a 45-megawatt cogeneration facility at Elk Hills that provides additional flexibility and reliability to support field operations. Within our Long Beach operations in the Los Angeles basin, we operate a 48-megawatt power generating facility that provides over 40% of our Long Beach operation’s electricity requirements. All of these facilities are integrated with our operations to improve their reliability and performance while reducing operating costs.

Steam Infrastructure

We own, control and operate all of our steam generation infrastructure in the San Joaquin basin, including steam generators, steam plants, steam distribution systems, steam injection lines and headers, water softeners and water disposal systems. We soften and self-supply water to generate steam, reducing our operating costs. This infrastructure is integral to our operations in the San Joaquin basin and supports our high margin and shallow- to medium-depth oil fields such as Kern Front and Lost Hills.

Gathering Systems

We own an extensive network of over 20,000 miles of oil and gas gathering lines. These gathering lines are dedicated almost entirely to collecting our oil and gas production and are in close proximity to field-specific facilities such as tank settings or central processing sites. These lines connect our producing wells and facilities to gathering networks, natural gas collection and compression systems, and water and steam processing, injection and distribution systems. Our oil gathering systems connect to multiple third-party transportation pipelines, which increases our flexibility to ship to various parties. In addition, virtually all of our natural gas facilities connect with major third-party natural gas pipeline systems. As a result of these connections, we typically have the ability to access multiple delivery points to improve the prices we obtain for our oil and natural gas production.

Oil and NGL Storage

Our tank storage capacity throughout California gives us flexibility for a period of time to store crude oil and NGLs, allowing us to continue production and avoid or delay any field shutdowns in the event of temporary power, pipeline or other shutdowns.

Employees

We had approximately 1,500 employees as of December 31, 2018 compared to approximately 1,450 as of December 31, 2017. The increase is primarily due to the conversion of certain long-term contractors to employees in 2018. Of the 1,500 employees, approximately 1,080 were employed in field operations and approximately 75 of those 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.

Regulation of the Oil and Natural Gas Industry

Our operations are subject to a wide range of federal, state and local laws and regulations. Those that specifically relate to oil and natural gas exploration and production are described in this section.

Regulation of Exploration and Production

Federal, state and local laws and regulations govern most aspects of exploration and production in California, including:

oil and natural gas production, including siting and spacing of wells and facilities on federal, state and private lands with associated conditions or mitigation measures;

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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;
sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and improved or enhanced recovery processes;
imposition of taxes and fees with respect to our properties and operations;
the conservation of oil and natural gas, including provisions for the unitization or pooling of oil and natural gas properties;
posting of bonds or other financial assurance to drill, operate and abandon or decommission wells and facilities; and
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.
DOGGR 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 (SEIS). In August 2018, BLM published a notice of intent to prepare an amendment to the Resource Management Plan and an associated SEIS regarding oil and gas exploration and production activities, including well stimulation, which process may impact future oil and gas leasing of federal lands in central California.
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 began implementing an electronic permitting system in 2018. DOGGR issued additional regulations in 2018 that impose more stringent inspection and integrity management requirements with respect to certain gas pipelines located in sensitive areas, and the Office of the State Fire Marshal intends to issue regulations in 2019 that would require retrofitting certain oil pipelines in the coastal zone with best available control technology to mitigate oil spills. DOGGR is also finalizing updated regulations governing management of idle wells and underground fluid injection, which are expected to be adopted early in 2019 and to include specific implementation periods. Pursuant to Assembly Bill 2729, which the Legislature enacted in 2016, DOGGR requires operators to either submit annual idle well management plans describing how they will plug and abandon or reactivate a specified percentage of long-term idle wells or pay additional annual fees for each such well. The updated underground injection regulations are expected to address injection approvals, project data requirements, testing of injection wells, monitoring and reporting requirements with respect to injection parameters, containment and incident response, among other topics. Finally, DOGGR announced that it is reviewing and intends to update its well construction regulations in the next two years.
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 into producing wells. Among other things, SB 4 requires operators to obtain specific well stimulation permits, make detailed 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. In 2017, the BLM rescinded its hydraulic fracturing regulations, which were being challenged in court, and is preparing a SEIS regarding well stimulation and other oil and gas activities on federal lands in central California. 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, impose setback distances from certain other land uses, 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. As written, the measure sought to prohibit the drilling of new oil and gas wells, hydraulic fracturing and other well-stimulation techniques and to phase out the injection of produced water. This measure was challenged in state court, and the Monterey County Superior Court issued a decision in December 2017, finding that the bans on drilling new wells and water injection are preempted by and invalid under existing state and federal regulations and, if implemented, would constitute a taking of our property 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 project involving hydraulic fracturing is proposed. Although the County is complying with and declined to appeal the Court's decision and settled the litigation, sponsors of the ballot measure have appealed.
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, conduct regional, community or field monitoring of air, soil or water quality, and require attainment plans to meet those regional standards, which may include significant mitigation measures or restrictions on development, economic activity and transportation in such region;
require various permits, approvals and mitigation measures before drilling, workover, production, underground fluid injection or waste disposal commences, or before facilities are constructed or put into operation;
require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and shutdown systems, and implementation of inspection, monitoring and repair programs to prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;
restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation and reclamation measures, impose energy efficiency or renewable energy standards on us or users of our products and services, and restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics;
restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced water or wastes, that can be released or discharged into the environment, or any other uses of those materials resulting from drilling, production, processing, power generation, transportation or storage activities;
limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat and other protected areas, and require the dedication of surface acreage for habitat conservation;
establish standards for the management of solid and hazardous wastes or the closure, abandonment, cleanup or restoration of former operations, such as plugging and abandonment of wells and decommissioning of facilities;
impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment with respect to our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;
impose taxes or fees with respect to the foregoing matters;
may expose us to litigation with government authorities, counterparties, special interest groups or others; and
may restrict our rate of oil, NGLs, natural gas and electricity production.

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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. 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. During the review, the state has restricted injection in certain formations or wells in several fields, including some operated by us, requested that we change injection zones in certain fields, and held certain pending injection permits in abeyance. We are coordinating with the state to change injection zones in certain fields to facilitate disposal of produced water in deeper formations where feasible or to increase recycling of produced water in pressure maintenance or waterfloods in lieu of disposal.

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

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

A number of international, federal, state, regional and local efforts seek to prevent or mitigate the effects of climate change or to track, mitigate and reduce GHG emissions associated with energy use and industrial activity, including operations of the oil and natural gas production sector and those who use our products as a source of energy or feedstocks. The EPA has adopted federal regulations to:
require reporting of annual GHG emissions from oil and gas exploration and production, 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 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 natural gas, propane and liquid transportation fuels sold for use in California;

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established a low carbon fuel standard and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels;
mandated that California derive 60% of its electricity for retail customers from renewable resources by 2030;
established a policy to derive all of California’s retail electricity from renewable or "zero-carbon" resources by 2045, subject to required evaluation of the feasibility by state agencies; and
imposed state goals to double the energy efficiency of buildings by 2030 and to reduce emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030.

The EPA and the California Air Resources Board (CARB) have also expanded direct regulation of methane as a contributor to GHG emissions. In 2016, the EPA adopted regulations to require additional emission controls for methane, volatile organic compounds and certain other substances for new or modified oil and natural gas facilities. Although the EPA proposed in 2018 to increase the flexibility of its 2016 methane requirements, 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 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.

Spin-Off and Reverse Stock Split
We were incorporated in Delaware as a wholly owned subsidiary of Occidental Petroleum Corporation (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.

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Available Information
We make available free of charge on our website, www.crc.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, our annual proxy statements and amendments to those reports, if any. Our website contains additional important information such as our Sustainability Report and descriptions of our health, safety, environmental and community outreach programs, as well as GAAP to non-GAAP reconciliations. Unless otherwise provided herein, information contained on our website is not part of this report.



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ITEM 1A
RISK FACTORS

Described below are certain risks and uncertainties that could adversely affect our business, financial condition, results of operations or cash flow. These risks are not the only risks we face. Our business could also be affected materially and adversely by other risks and uncertainties that are not currently known to us or that we currently deem to be immaterial.

Prices for our products can fluctuate widely and an extended period of low prices could adversely affect our financial condition, results of operations, cash flow and ability to invest in our assets.

Our financial condition, results of operations, cash flow and ability to invest in our assets are highly dependent on oil, natural gas and NGL prices. Historically, the markets for these commodities have been volatile and they are likely to continue to be so. We are particularly dependent on Brent crude prices that have been as low as $27.88 per barrel and as high as $115.19 per barrel during the period between 2014 and 2018. Factors affecting oil, natural gas and NGL prices include:

changes in domestic and global supply and demand;
domestic and global inventory levels;
political and economic conditions;
the actions of OPEC and other significant producers and governments;
changes or disruptions in actual or anticipated production, refining and processing;
worldwide drilling and exploration activities;
government energy policies and regulation, including with respect to climate change;
the effects of conservation;
weather conditions and other seasonal impacts;
speculative trading in derivative contracts;
currency exchange rates;
technological advances;
transportation and storage capacity, bottlenecks and costs in producing areas;
the price, availability and acceptance of alternative energy sources;
regional market conditions; and
other matters affecting the supply and demand dynamics for these products.

Lower prices could have adverse effects on our business, financial condition, results of operations and cash flow, including:

reducing our proved oil and gas reserves over time, including as a result of impairments of existing reserves;
limiting our ability to grow or maintain future production;
causing a reduction in our borrowing base under our 2014 Revolving Credit Facility, which could affect our liquidity;
reducing our ability to make interest payments or maintain compliance with financial covenants in the agreements governing our indebtedness, which could trigger mandatory loan repayments and default and foreclosure by our lenders and bondholders against our assets;
forcing monetization events and potential issues under our JV arrangements;
affecting our ability to attract counterparties and enter into commercial transactions, including hedging transactions; and
limiting our access to funds through the capital markets and the price we could obtain for asset sales or other monetization transactions or our equity and debt securities.

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A sustained period of low prices for oil, natural gas and NGLs would reduce our cash flows from operations and could reduce our borrowing capacity or cause a default under our financing agreements. Under these conditions, if we were unable to improve 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, dilution of equity and further covenant restrictions. Past refinancing activities have resulted in increases in our annual interest expense and future refinancing activities may have the same or greater effect.

Our hedging program does not provide downside protection for all of our production in 2019 and beyond. As a result, our hedges do not fully protect us from commodity price reductions and we may be unable to enter into acceptable additional hedges in the future.

Our lenders require us to comply with covenants that limit our borrowing capabilities and could restrict our ability to use or access capital.

Our 2014 Revolving Credit Facility is an important source of our liquidity and we may need to rely on this facility to fund a portion of our future capital and operating costs. Our ability to borrow under our 2014 Revolving Credit Facility is limited by our borrowing base, the size of our lenders' commitments and our ability to comply with covenants, including a minimum monthly liquidity requirement of $150 million. As of December 31, 2018, we had approximately $298 million of available borrowing capacity, before taking into account the minimum monthly liquidity requirement.

As of December 31, 2018, the lenders' aggregate commitment under our 2014 Revolving Credit Facility was $1 billion. The borrowing base under our 2014 Revolving Credit Facility is currently set at $2.3 billion and is redetermined each May 1 and November 1. The lenders take into account the $1.3 billion outstanding under our 2017 Credit Agreement in determining the total commitment that could be made available in the future under the 2014 Revolving Credit Facility. Our lenders determine our borrowing base by reference to the value of our reserves, which is influenced by commodity prices, expected future cash flows and other factors. If our lenders were to reduce our borrowing base significantly, the amount of availability under our 2014 Revolving Credit Facility could be reduced which could have an adverse effect on our liquidity and financial condition.

The financial covenants that we must satisfy under our 2014 Revolving Credit Facility include a monthly minimum liquidity test and certain financial ratios that measure our leverage and fixed interest charges on a quarterly basis and the present value of our reserves on a semi-annual basis. These covenants could limit our ability to borrow under our 2014 Revolving Credit Facility or obtain additional financing through the capital markets or otherwise. Certain other agreements governing our long-term indebtedness also include financial ratios that are generally less restrictive than our 2014 Revolving Credit Facility.
  
If we were to breach any of the covenants under our 2014 Revolving Credit Facility, the lenders would be permitted to cease lending under the facility, accelerate the repayment of the outstanding amounts due and foreclose against the assets securing them.

For a further description of our 2014 Revolving Credit Facility and our other credit agreements, see Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Credit Agreements.


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We have significant indebtedness that could limit our financial and operating flexibility and make us more vulnerable in economic downturns.

As of December 31, 2018, the face value of our outstanding long-term consolidated indebtedness was $5.3 billion. Our financing agreements permit us to incur significant additional indebtedness as well as certain other obligations. In addition, we may seek amendments or waivers from our existing lenders and bondholders to the extent we need to incur indebtedness above amounts currently permitted by our financing agreements.

Our level of indebtedness may have adverse effects on our business, financial condition, cash flows or results of operations, including:

jeopardizing our ability to execute our business plans;
increasing our vulnerability to adverse changes in economic and industry conditions related to our business;
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;
limiting our ability to fund capital investments, react to competitive pressures and engage in certain transactions that might otherwise be beneficial to us;
defaulting on commercial agreements with our JV partners; and
failing to redeem the interests held by our JV partners.

Our financing agreements also include covenants that restrict management's discretion to operate our business in certain circumstances. These restrictions include limitations that could affect our ability to:

incur additional indebtedness and granting additional liens;
repay junior indebtedness, including our Second Lien Notes and Senior Notes;
make investments;
enter into JVs;
pay dividends and making other restricted payments;
selling assets;
use the proceeds of asset sales for certain purposes;
enter into mergers or acquisitions; and
release 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 Agreements and the documents governing our indebtedness that are filed with the SEC.

Our financing agreements, including the 2014 Revolving Credit Facility, contain customary cross-default mechanisms that provide that an event of default under any one of those agreements may trigger an event of default under all of those agreements. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to implement our business plan, make capital expenditures or finance our operations.

A significant portion of our outstanding indebtedness bears interest at variable rates. Although we have purchased derivative contracts that limit our interest rate exposure for a portion of this indebtedness, a rise in interest rates will increase our interest expense to the extent we do not have interest-rate hedges and could limit our liquidity and our ability to comply with our debt covenants.

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, 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. Failure to make a scheduled payment or to comply with 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 indebtedness.

31




Our business requires substantial capital investments, which may include acquisitions. We may be unable to fund these investments 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.

Our exploration, development and acquisition activities require substantial capital investments. Historically, we have funded our capital investments through a combination of cash flow from operations, borrowings under our 2014 Revolving Credit Facility and JV arrangements. We seek to manage our capital investments to closely align with projected cash flow from operations. Accordingly, a reduction in projected operating cash flow could cause us to reduce our future capital investments. In general, the ability to execute our capital plan depends on a number of variables, including:

the amount of oil, gas and NGLs we are able to produce;
commodity prices;
regulatory and third-party approvals;
our ability to timely drill, complete and stimulate wells;
our ability to secure equipment, services and personnel; and
the availability of external sources of financing.

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 levels and development activities and limit our ability to make acquisitions.

Unless we make sufficient capital investments and conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our ability to make the necessary long-term capital investments or acquisitions needed to maintain or expand our reserves may be impaired to the extent we have insufficient cash flow from operations or liquidity to fund those activities. Over the long term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.

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

Many uncertainties exist in estimating quantities of proved reserves and related future net cash flows. Our estimates are based on various assumptions that require significant judgment in the evaluation of available information. Our assumptions may ultimately prove to be inaccurate. Additionally, reservoir data may change over time as more information becomes available from development and appraisal activities.

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

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


32



In addition, our reserves information represents estimates prepared by internal engineers. Although over 80% of our 2018 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 facilities costs.

Changes in these variables and assumptions could require us to make significant negative reserves revisions, which could affect our liquidity by reducing the borrowing base under our 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.

Acquisition and disposition activities and our JVs involve substantial risks.

Our acquisition activities carry risks that we may:

not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances;
bear unexpected integration costs or experience other integration difficulties;
experience share price declines based on the market’s evaluation of the activity;
assume liabilities that are greater than anticipated; and
be exposed to currency, political, marketing, labor and other risks, particularly associated with investments in foreign assets.

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.

Part of our business strategy involves entering into JVs and divesting non-core assets. Our JVs and disposition activities carry risks that we may:

not be able to realize reasonable prices or rates of return for assets;
be required to retain liabilities that are greater than desired or anticipated;
experience increased operating costs; and
reduce our cash flows if we cannot replace associated revenue.

There can be no assurance that we will be able to successfully enter into new JVs or that JVs will occur in the time frames or with economic terms that we expect. We may also be unable to divest assets on financially attractive terms or at all. Our ability to enter into JVs and sell assets is also limited by the agreements governing our indebtedness.

If we are not able to make acquisitions, we may not be able to grow our reserves or develop our properties in a timely manner or at all. If we are not able to sell assets as needed or enter into JVs, we may not be able to generate proceeds to support our liquidity and capital investments. Any of the foregoing could adversely affect our business, financial condition, cash flows and results of operations.


33



Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products. Federal, state and local agencies may assert overlapping authority to regulate 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 state agencies as well as certain cities and counties have significantly revised their regulations, regulatory interpretations and data collection requirements and plan to issue additional regulations of certain oil and gas activities in 2019. 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 Items 1 and 2 – Business and Properties – 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, various government authorities have sought to restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics. Federal and state pipeline safety agencies have adopted or proposed regulations to expand their jurisdiction to include more gas and liquid gathering lines and pipelines and to impose additional mechanical integrity 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, including proposed setback distances from other land uses. Such requirements or associated litigation could result in potentially significant added costs to comply, delay or curtail our exploration, development, fluid injection and disposal or production activities, preclude us from drilling, completing or stimulating wells, or otherwise restrict our ability to access and develop mineral rights, any of which could have an adverse effect on our expected production, other operations and financial condition.

Changes in elected officials could result in different approaches to the regulation of the oil and gas industry. In 2018, California elected a new governor who took office in January 2019. Many representatives in the Legislature have also changed, with the commencement of a new two-year legislative session. We cannot predict the actions the 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.


34



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. Wells we do drill may not yield production in economic quantities or generate our expected VCI.

The exploration and development of oil and gas properties depend in part on our analysis of geophysical, geologic, engineering, production and other technical data and processes, including the interpretation of 3D seismic data. This analysis is often inconclusive or subject to varying interpretations. We also bear the risks of equipment failures, accidents, environmental hazards, unusual geological formations or unexpected pressure or irregularities within formations, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes, disappointing drilling results or reservoir performance (including lack of production response to workovers or improved and enhanced recovery efforts) and other associated risks.

We allocate capital by reference to a VCI metric. We calculate the VCI of a well or project at the time capital is allocated and frequently re-calculate the VCI after a well or project is completed. VCIs are calculated based on internal estimates of future cash flows and capital investment and are inherently uncertain. 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.

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-type contracts. Overruns in budgeted investments is a common risk associated with oil and gas operations.

Any of the forgoing operational or financial risks could cause actual results to differ materially from the expected VCI or cause a well or project to become uneconomic or less profitable than forecast.

We have specifically identified locations for drilling over the next several years, which represent a significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate. We cannot guarantee that 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 14% of our total net undeveloped acreage at December 31, 2018.

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, which are in unproven geologic plays. Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, capital availability, costs, drilling results, regulatory approvals, available transportation capacity and other factors. We may not find commercial amounts of oil or natural gas or the costs of drilling completing and operating wells in these locations may be higher than initially expected. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. In either case, the value of our undeveloped acreage may decline and could be impaired.

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.


35



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

Our commodity-price risk-management activities may prevent us from realizing the full benefits of price increases above any levels set in certain derivative instruments we may use to manage price risk. For example, in 2018, we settled hedges that had the effect of reducing our realized oil price by $7.51 per barrel. 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.

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, some of which are still ongoing. These regulations may affect both the size of positions that we may enter and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, the effects of these regulations could reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. Recently, proposals have been made by U.S. regulators which would implement a new approach for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory capital rules, referred to as the standardized approach for counterparty credit risk or SA-CCR. If adopted as proposed, certain financial institutions would be required to comply with the new SA-CCR rules beginning on July 1, 2020 and the rules could significantly increase the capital requirements for certain participants in the OTC derivatives market in which we participate. These increased capital requirements could result in significant additional costs being passed through to end-users like us or reduce the number of participants or products available to us in the OTC derivatives market. The effects of these regulations could reduce our hedging opportunities, or substantially increase the cost of hedging, which could adversely affect our revenues and cash flow. 

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, which could also adversely affect our hedging opportunities.

Adverse tax law changes may affect our operations.

In California, there have been numerous proposals for additional income, sales, excise and property taxes, including taxes on oil and gas production. Although the proposals have not become law, campaigns by various interest groups could lead to additional future taxes. The imposition of increased taxes could significantly reduce our profit margins and cash flow and could ultimately reduce our capital investments and growth plans.

36




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

Our operations are concentrated in California. Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions. These include local price fluctuations, changes in state or regional laws and regulations affecting our operations and other regional supply and demand factors, including gathering, pipeline, transportation and storage capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. Our operations are also exposed to natural disasters and other nature-related events common to California, such as wildfires, mudslides, high winds and earthquakes. The concentration of our operations in California and limited local storage options also increase our exposure to mechanical failures, industrial accidents or labor difficulties, including those affecting our operations, our supply chain and those who purchase, transport or use our products. 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.

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 Items 1 and 2 – Business and Properties – Regulation of the Oil and Natural Gas Industry. California's cap-and-trade program operates under a market system and the costs of such allowances per metric ton of GHG emissions are expected to increase in the future as CARB tightens program requirements and annually increases the minimum state auction price of allowances and reduces the state's GHG emissions cap.

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. For example, former Governor Brown issued executive orders in 2018 setting a target of at least five million "zero-emission" vehicles in California by 2030 and a goal for the state to be “carbon-neutral” by 2045. A bill has been introduced in the California Legislature that seeks to prohibit the sale or registration of new automobiles in California with internal combustion engines by 2040. 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, and various state and local agencies are conducting increased regional, community and field air monitoring specifically with respect to oil and natural gas operations. In addition, California air quality laws and regulations, particularly in southern and central California where most of our operations are located, are in most instances more stringent than analogous federal laws and regulations. For example, the San Joaquin Valley will be required to adopt more rigorous attainment plans under the Clean Air Act to comply with federal ozone and particulate matter standards, and these efforts could affect our activities in the region and our ability and cost to obtain permits for new or modified operations.


37



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 and our assets are subject to risks such as fires, explosions, releases, discharges, equipment or information technology failures and industrial accidents, as are the assets and properties of third parties who supply us with energy, equipment and services or who purchase, transport or use our products. In addition, events such as earthquakes, floods, mudslides, wildfires, high winds, droughts, cyber-security or terrorist attacks and other events may cause operations to cease or be curtailed and could adversely affect our business, workforce and the communities in which we operate. 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-security attacks could adversely affect us.

We rely on electronic systems and networks to communicate, control and manage our exploration, development and production activities. We also use these systems and networks to prepare our financial management and reporting information, to analyze and store data and to communicate internally and with third parties, including our service providers. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected.

Cyber-security attacks on businesses have escalated and become more sophisticated in recent years and include attempts to gain unauthorized access to data, malicious software, ransomware and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential information or the corruption of data. In addition, our vendors, customers and other business partners may separately suffer disruptions or breaches from cyber-security attacks that, in turn, could adversely impact our operations and compromise our information. If we or the third parties with whom we interact were to experience a successful attack, the potential consequences to our business, workforce and the communities in which we operate could be significant including financial losses, loss of business, litigation risks and damage to reputation. As the sophistication of cyber-security attacks continues to evolve, we may be required to expend additional resources to further enhance our security.

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

Not applicable.

ITEM 3
LEGAL PROCEEDINGS

For information regarding legal proceedings, see Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Lawsuits, Claims, Commitments and Contingencies and in Item 8 – Financial Statements and Supplementary Data – Note 8 Lawsuits, Claims, Commitments and Contingencies.

ITEM 4
MINE SAFETY DISCLOSURES

Not applicable.


38



EXECUTIVE OFFICERS

Executive officers are appointed annually by the Board of Directors. The following table sets forth our current executive officers:
Name
 
Employment History
 
Age at February 27, 2019
Todd A. Stevens
 
President, Chief Executive Officer and Director since 2014; Occidental Petroleum Corporation Vice President - Corporate Development 2012 to 2014; Oxy Oil & Gas Vice President - California Operations 2008 to 2012; Occidental Petroleum Corporation Vice President - Acquisitions and Corporate Finance 2004 to 2012.
 
52
Marshall D. Smith
 
Senior Executive Vice President and Chief Financial Officer since 2014; Ultra Petroleum Corporation Senior Vice President and Chief Financial Officer 2011 to 2014; Ultra Petroleum Corporation Chief Financial Officer 2005 to 2014.
 
59
Shawn M. Kerns
 
Executive Vice President - Operations and Engineering - 2018; Executive Vice President - Corporate Development 2014 to 2018; Vintage Production California President and General Manager 2012 to 2014; Occidental of Elk Hills General Manager 2010 to 2012; Occidental of Elk Hills Asset Development Manager 2008 to 2010.
 
48
Francisco J. Leon
 
Executive Vice President - Corporate Development and Strategic Planning - 2018; Vice President - Portfolio Management and Strategic Planning 2014 to 2018; Occidental Director - Portfolio Management 2012 to 2014; Occidental Director of Corporate Development and M&A 2010 to 2012; Occidental Manager of Business Development 2008 to 2010.
 
42
Roy M. Pineci
 
Executive Vice President - Finance since 2014; Occidental Vice President and Controller 2008 to 2014; Occidental Oil and Gas Senior Vice President 2007 to 2008.
 
56
Michael L. Preston
 
Executive Vice President, General Counsel and Corporate Secretary since 2014; Occidental Oil and Gas Vice President and General Counsel 2001 to 2014.
 
54
Charles F. Weiss
 
Executive Vice President - Public Affairs since 2014; Occidental Vice President, Health, Environment and Safety 2007 to 2014.
 
55
Darren Williams
 
Executive Vice President - Operations and Geoscience - 2018; Executive Vice President - Exploration 2014 to 2018; Marathon Upstream Gabon Limited President and Africa Exploration Manager 2013 to 2014; Marathon Oil Oklahoma Subsurface Manager 2010 to 2013; Marathon Oil Gulf of Mexico Exploration and Appraisal Manager 2008 to 2010.
 
47
    

39



PART II
ITEM 5
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information for Common Stock

Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol "CRC."
Holders of Record    
Our common stock was held by approximately 20,700 stockholders of record at December 31, 2018.
Dividend Policy    
No dividends were paid in 2018, 2017 and 2016, and we do not anticipate paying any dividends on our common stock in the foreseeable future. Covenants under our credit agreements generally restrict the payment of cash dividends on our stock, subject to certain exceptions. See Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Credit Agreements for a description of limitations on paying dividends under our credit facilities.

Securities Authorized for Issuance Under Equity Compensation Plans

A description of the stock-based compensation plans can be found in Item 8 – Financial Statements and Supplementary Data – Note 11 Stock-Based Compensation. The aggregate number of shares of our common stock authorized for issuance under our stock-based compensation plans for our executives, employees and non-employee directors is 6.2 million, of which approximately 4.9 million had been issued or reserved through December 31, 2018.

The following is a summary of the securities available for issuance under such plans as of December 31, 2018:
a)
Number of securities to be issued upon exercise of outstanding options, warrants and rights
 
b)
Weighted-average exercise price of outstanding options, warrants and rights
 
c)
Number of securities remaining available for future issuance under equity compensation plans (excluding securities in column (a))
2,354,569
 
$62.82 (a)
 
1,253,892 (b)
(a)
Exercise price applies only to approximately 1.3 million options included in column (a) and not to any other awards.
(b)
Includes 656,929 shares available under our 2014 Employee Stock Purchase Plan (ESPP) for purchase at 85% of the lower of the market price at either (i) the beginning of a quarter or (ii) the end of a quarter.

Performance Graph

The following graph compares the cumulative total return to stockholders on our common stock relative to the cumulative total returns of the S&P 500 and Dow Jones U.S. Exploration and Production indexes and our peer groups (with reinvestment of all dividends). The graph assumes that on December 1, 2014, the date our common stock began trading on the NYSE, $100 was invested in our common stock, in each index and in each of the peer group companies' common stock weighted by their relative market values within the peer group, and that all dividends were reinvested. The results shown are based on historical results and are not intended to suggest future performance.

Our 2018 peer group consists of Cabot Oil & Gas Corporation; Callon Petroleum Company; Carrizo Oil & Gas, Inc.; Cimarex Energy Co.; Denbury Resources, Inc.; Diamondback Energy, Inc.; EP Energy Corporation; Gulfport Energy Corporation; Laredo Petroleum, Inc.; Matador Resources Company; Murphy Oil Corporation; Newfield Exploration Company; Oasis Petroleum Inc.; Parsley Energy, Inc.; PDC Energy, Inc.; QEP Resources, Inc.; Range Resources Corporation; SM Energy Company; Southwestern Energy Company; Whiting Petroleum Corporation and WPX Energy, Inc.

Our 2017 peer group included Cabot Oil and Gas Corporation; Cimarex Energy Co.; Concho Resources Inc.; Denbury Resources Inc.; Energen Corporation; EP Energy Corporation; Murphy Oil Corporation; Newfield Exploration Company; Oasis Petroleum Corporation; Parsley Energy, Inc.; QEP Resources, Inc.; Range Resources Corporation; SM Energy Company; Whiting Petroleum Corporation and WPX Energy, Inc. Energen Corporation is excluded from the graph below due to its acquisition by Diamondback Energy, Inc. in 2018.

40




a2018performancegrapha07.jpg

 
 
 
 
December 31,
 
 
12/1/2014
 
2014
 
2015
 
2016
 
2017
 
2018
 
 
 
 
 
 
 
 
 
 
 
 
 
CRC
 
$
100

 
$
75

 
$
32

 
$
29

 
$
27

 
$
23

S&P 500
 
$
100

 
$
100

 
$
101

 
$
113

 
$
138

 
$
132

Dow Jones US Exploration & Production
 
$
100

 
$
99

 
$
76

 
$
94

 
$
95

 
$
78

2018 Peer Group
 
$
100

 
$
95

 
$
58

 
$
85

 
$
70

 
$
53

2017 Peer Group
 
$
100

 
$
96

 
$
62

 
$
92

 
$
81

 
$
53


* This performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing of CRC under the Securities Act of 1933, as amended, or the Exchange Act except to the extent that we specifically request it be treated as soliciting material or specifically incorporate it by reference.

41



ITEM 6
SELECTED FINANCIAL DATA
Prior to the Spin-off on November 30, 2014, financial data was derived from Occidental's California oil and gas exploration and production operations and related assets, liabilities and obligations (California business), which we assumed with the Spin-off. All financial information presented after the Spin-off represents our stand-alone consolidated results of operations, financial position and cash flows. Accordingly, for the year ended December 31, 2014, the statement of operations and cash flows data includes the consolidated results for the month ended December 31, 2014 and the combined results of the California business prior to the Spin-off.
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in millions, except for per share data)
Statement of Operations Data
 

 
 

 
 

 
 

 
 

Total revenues and other
$
3,064

 
$
2,006

 
$
1,547

 
$
2,403

 
$
4,173

Income (loss) before income taxes
$
429

 
$
(262
)
 
$
201

 
$
(5,476
)
 
$
(2,421
)
Net income (loss) attributable to common stock
$
328

 
$
(266
)
 
$
279

 
$
(3,554
)
 
$
(1,434
)
Per common share
 
 
 
 
 
 
 
 
 
Basic
$
6.77

 
$
(6.26
)
 
$
6.76

 
$
(92.79
)
 
$
(37.54
)
Diluted
$
6.77

 
$
(6.26
)
 
$
6.76

 
$
(92.79
)
 
$
(37.54
)
Statement of Cash Flows Data
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
461

 
$
248

 
$
130

 
$
403

 
$
2,371

Capital investments
$
(690
)
 
$
(371
)
 
$
(75
)
 
$
(401
)
 
$
(2,089
)
Acquisitions and other
$
(553
)
 
$
(2
)
 
$

 
$
(151
)
 
$
(292
)
Net (repayments) borrowings and related costs
$
(26
)
 
$
(18
)
 
$
(73
)
 
$
356

 
$
6,290

Contributions from noncontrolling interest holders, net
$
796

 
$
98

 
$

 
$

 
$

Distributions paid to noncontrolling interest holders
$
(121
)
 
$
(8
)
 
$

 
$

 
$

Spin-off related dividends to Occidental
$

 
$

 
$

 
$

 
$
(6,000
)
Distributions to Occidental, net
$

 
$

 
$

 
$

 
$
(335
)
Dividends per common share
$

 
$