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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2017
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to .
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Delaware
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72-1133047
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(State of incorporation)
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(I.R.S. Employer Identification No.)
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4 Waterway Square Place,
Suite 100,
The Woodlands, Texas
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77380
(Zip Code)
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(Address of principal executive offices)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, par value $0.01 per share
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New York Stock Exchange
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Large accelerated filer
þ
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Accelerated filer
¨
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Non-accelerated filer
¨
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Smaller reporting company
¨
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Emerging growth company
¨
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(Do not check if a smaller reporting company)
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Page
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PART I
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Items 1 and 2.
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Item 1A.
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Item 1B.
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Item 3.
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Item 4.
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PART II
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Item 5.
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Item 6.
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Item 7.
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Page
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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PART III
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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PART IV
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Item 15.
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•
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oil, natural gas and natural gas liquids prices;
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•
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actions of the Organization of the Petroleum Exporting Countries (OPEC), its members and other state-controlled oil companies relating to oil price and production controls;
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•
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environmental liabilities that are not covered by an effective indemnity or insurance;
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•
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legislation or regulatory initiatives intended to address seismic activity;
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•
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the timing and our success in discovering, producing and estimating reserves;
|
•
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sustained decline in commodity prices resulting in impairments of assets;
|
•
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ability to develop existing reserves or acquire new reserves;
|
•
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the availability and volatility of the securities, capital or credit markets and the cost of capital;
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•
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maintaining sufficient liquidity to fund our operations and business strategies;
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•
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the accuracy of and fluctuations in our reserves estimates due to sustained low commodity prices, incorrect assumptions and other causes;
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•
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operating hazards inherent in the exploration for and production of oil and natural gas;
|
•
|
general economic, financial, industry or business trends or conditions;
|
•
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the impact of, and changes in, legislation, law and governmental regulations, including the Tax Cuts and Jobs Act (the Tax Act) and those related to hydraulic fracturing, the environment, natural resources, climate change and over-the-counter derivatives;
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•
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land, legal, regulatory, and ownership complexities inherent in the U.S. and Chinese oil and gas industries;
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•
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the impact of regulatory approvals;
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•
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the ability and willingness of current or potential lenders, derivative contract counterparties, customers and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us, including the creditworthiness of such counterparties;
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•
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the prices and quantities of commodities reflected in our commodity derivative arrangements as compared to the actual prices or quantities of commodities we produce or use;
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•
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the volatility, instrument terms and liquidity in the commodity futures and commodity and financial derivatives markets;
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•
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drilling risks and results;
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•
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the prices and availability of goods and services;
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•
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the cost and availability of drilling rigs and other oilfield services;
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•
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global events that may impact our domestic and international operating contracts, markets and prices;
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•
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our ability to monetize non-strategic assets, repay or refinance our existing indebtedness and the impact of changes in our investment ratings;
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•
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labor conditions;
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•
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severe weather conditions;
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•
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competitive conditions;
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•
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terrorism or civil or political unrest in a region or country;
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•
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electronic, cyber or physical security breaches;
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•
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changes in federal or state tax rates;
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•
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inflation rates;
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•
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the effect of worldwide energy conservation measures;
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•
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the price and availability of, and demand for, competing energy sources;
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•
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our ability to successfully execute our business and financial plans and strategies;
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•
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the availability (or lack thereof) of acquisition, disposition or combination opportunities; and
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•
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the other factors affecting our business described under the captions "
Risk Factors
"
and
"
Management’s Discussion and Analysis of Financial Condition and Results of Operations
—
Critical Accounting Policies and Estimates
."
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Items 1 and 2
.
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Business and Properties
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•
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Invested
$1.156 billion
(excluding acquisitions, capitalized interest and capitalized internal costs) primarily in our highest value plays, SCOOP and STACK, located in the Anadarko Basin of Oklahoma;
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•
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Increased 2017 average daily domestic production by 10%
over 2016 to 152
(1)
MBOEPD (excluding 9.4 MBOEPD for the sale of our Texas assets sold in 2016);
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•
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The Anadarko Basin contributed more than 36 MMBOE in production and comprised more than 63% of total company production. Anadarko Basin production grew 16% year-over-year in 2017 with oil volumes increasing 17% over the same period. The Anadarko Basin holds our greatest concentration of proved reserves with over 475 MMBOE. At year-end 2017, we held approximately 369,000 net acres in the Anadarko Basin;
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•
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Increased year-end 2017 estimated proved reserves
33%
to 680 MMBOE (
59%
proved developed). Substantially all of the total proved reserves are located onshore in the United States (total domestic reserves are approximately 37% oil, 21% NGLs and 42% natural gas);
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•
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The PV-10
(2)
associated with our proved reserves increased by
84%
to
$4.9 billion
compared to the prior year-end primarily due to higher commodity prices and the significant increase in proved reserves, partially offset by higher drilling and development costs related to more intensive hydraulic fracturing completions;
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•
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Lowered our average domestic lease operating expenses
4%
, on a per barrel basis, during 2017;
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•
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Completed and commissioned the Barton Creek Water Recycle Facility in STACK, located in Kingfisher County, Oklahoma, which is now processing more than 30,000 barrels of water per day; and
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•
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At year-end 2017, we had
$326 million
of cash and cash equivalents on our consolidated balance sheet and had no borrowings outstanding under our revolving credit facility or money market lines of credit.
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(1)
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Includes 2 MBOEPD of natural gas produced and consumed in operations.
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(2)
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PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented under U.S. generally accepted accounting principles) because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor the standardized measure represents an estimate of the fair market value of our crude oil and natural gas properties. PV-10 is used in the oil and natural gas industry as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. The following table shows a reconciliation of the standardized measure to PV-10:
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Domestic
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China
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Total
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||||||
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(In millions)
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||||||||||
December 31, 2017:
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||||||
Standardized measure of discounted future net cash flows
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$
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4,354
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$
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47
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$
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4,401
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Present value of future income tax expense
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545
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—
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545
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|||
Proved reserve PV-10 value (before tax)
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$
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4,899
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$
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47
|
|
|
$
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4,946
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||||||
December 31, 2016:
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||||||
Standardized measure of discounted future net cash flows
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$
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2,520
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$
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64
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$
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2,584
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Present value of future income tax expense
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101
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|
|
—
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|
101
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|||
Proved reserve PV-10 value (before tax)
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$
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2,621
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$
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64
|
|
|
$
|
2,685
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•
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Improve our rates of return through continued high-grading of our capital investments;
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•
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Continue to grow oil production;
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•
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Exercise capital discipline; and
|
•
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Improve or maintain our leverage ratios as defined under our revolving credit facility.
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(1)
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Includes
4.5
Bcf of natural gas produced and consumed in operations.
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Oil and
Condensate
|
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Natural
Gas
|
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NGLs
|
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Total
|
||||
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(MMBbls)
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(Bcf)
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(MMBbls)
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(MMBOE)
|
||||
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
||||
Domestic
|
|
136
|
|
|
1,099
|
|
|
78
|
|
|
398
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China
|
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2
|
|
|
—
|
|
|
—
|
|
|
2
|
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Total proved developed
|
|
138
|
|
|
1,099
|
|
|
78
|
|
|
400
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
||||
Domestic
|
|
112
|
|
|
605
|
|
|
68
|
|
|
280
|
|
China
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total proved undeveloped
|
|
112
|
|
|
605
|
|
|
68
|
|
|
280
|
|
Total proved reserves
|
|
250
|
|
|
1,704
|
|
|
146
|
|
|
680
|
|
|
|
Proved Reserves
|
|
Percentage of
Proved Reserves
|
||
|
|
(MMBOE)
|
|
|
||
Domestic:
|
|
|
|
|
||
STACK
|
|
284
|
|
|
42
|
%
|
SCOOP
|
|
193
|
|
|
28
|
%
|
Williston Basin
|
|
67
|
|
|
10
|
%
|
Arkoma
|
|
59
|
|
|
9
|
%
|
Central Basin
|
|
44
|
|
|
6
|
%
|
GMBU
|
|
31
|
|
|
5
|
%
|
Total domestic
|
|
678
|
|
|
100
|
%
|
International:
|
|
|
|
|
||
China
|
|
2
|
|
|
—
|
%
|
Total
|
|
680
|
|
|
100
|
%
|
|
Production
|
|
Average Realized Prices
(1)
|
|
Average Production Cost
(2)
|
||||||||||||||||||||||||||||||
|
Crude oil and condensate
|
|
Natural gas
|
|
NGLs
|
|
Total
|
|
Crude oil and condensate
|
|
Natural gas
|
|
NGLs
|
|
Total
|
|
Lease Operating Expense
|
|
Transportation and processing
|
||||||||||||||||
|
(MBbls)
|
|
(Bcf)
|
|
(MBbls)
|
|
(MBOE)
|
|
(Per Bbl)
|
|
(Per Mcf)
|
|
(Per Bbl)
|
|
(Per BOE)
|
|
(Per BOE)
|
|
(Per BOE)
|
||||||||||||||||
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
SCOOP
|
3,944
|
|
|
48.2
|
|
|
5,640
|
|
|
17,619
|
|
|
$
|
49.06
|
|
|
$
|
2.77
|
|
|
$
|
25.97
|
|
|
$
|
26.87
|
|
|
$
|
1.26
|
|
|
$
|
4.31
|
|
STACK
|
8,403
|
|
|
35.1
|
|
|
4,456
|
|
|
18,717
|
|
|
50.47
|
|
|
2.65
|
|
|
28.01
|
|
|
34.33
|
|
|
2.26
|
|
|
3.86
|
|
||||||
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
SCOOP
|
4,125
|
|
|
47.9
|
|
|
5,356
|
|
|
17,467
|
|
|
$
|
39.27
|
|
|
$
|
2.24
|
|
|
$
|
19.63
|
|
|
$
|
21.45
|
|
|
$
|
1.14
|
|
|
$
|
4.19
|
|
STACK
|
6,464
|
|
|
25.7
|
|
|
3,175
|
|
|
13,929
|
|
|
41.59
|
|
|
2.29
|
|
|
19.86
|
|
|
28.14
|
|
|
2.54
|
|
|
3.37
|
|
||||||
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
SCOOP
|
3,779
|
|
|
43.2
|
|
|
4,871
|
|
|
15,857
|
|
|
$
|
42.67
|
|
|
$
|
2.38
|
|
|
$
|
18.97
|
|
|
$
|
22.49
|
|
|
$
|
1.33
|
|
|
$
|
4.15
|
|
STACK
|
3,645
|
|
|
11.0
|
|
|
1,396
|
|
|
6,886
|
|
|
42.99
|
|
|
2.49
|
|
|
19.02
|
|
|
30.61
|
|
|
2.58
|
|
|
2.04
|
|
(1)
|
Does not include impact of derivative gains or losses.
|
(2)
|
Production costs include cost to operate and maintain our wells, related equipment and supporting facilities, including the cost of labor, well service and repair, gathering, processing, transportation, as well as production-related general and administrative costs. Production costs exclude severance taxes and property taxes.
|
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
203
|
|
|
46
|
|
|
136
|
|
|
60
|
|
|
123
|
|
|
57
|
|
Nonproductive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
China:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Nonproductive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploratory well total
|
|
203
|
|
|
46
|
|
|
136
|
|
|
60
|
|
|
124
|
|
|
58
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
146
|
|
|
74
|
|
|
47
|
|
|
31
|
|
|
158
|
|
|
78
|
|
China:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|
3
|
|
Development well total
|
|
146
|
|
|
74
|
|
|
47
|
|
|
31
|
|
|
174
|
|
|
81
|
|
Total wells
|
|
349
|
|
|
120
|
|
|
183
|
|
|
91
|
|
|
298
|
|
|
139
|
|
|
|
Company
Operated Wells
|
|
Outside
Operated Wells
|
|
Total
Productive Wells
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil
|
|
2,866
|
|
|
2,271
|
|
|
1,187
|
|
|
94
|
|
|
4,053
|
|
|
2,365
|
|
Natural gas
|
|
843
|
|
|
623
|
|
|
1,012
|
|
|
124
|
|
|
1,855
|
|
|
747
|
|
China:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil
|
|
6
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
3
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil
|
|
2,872
|
|
|
2,274
|
|
|
1,187
|
|
|
94
|
|
|
4,059
|
|
|
2,368
|
|
Natural gas
|
|
843
|
|
|
623
|
|
|
1,012
|
|
|
124
|
|
|
1,855
|
|
|
747
|
|
Total
|
|
3,715
|
|
|
2,897
|
|
|
2,199
|
|
|
218
|
|
|
5,914
|
|
|
3,115
|
|
|
|
Developed Acres
|
|
Undeveloped Acres
|
||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
|
|
(In thousands)
|
||||||||||
Domestic:
|
|
|
|
|
|
|
|
|
||||
Anadarko Basin
|
|
561
|
|
|
311
|
|
|
119
|
|
|
58
|
|
Arkoma Basin
|
|
310
|
|
|
143
|
|
|
4
|
|
|
1
|
|
Uinta Basin
|
|
222
|
|
|
159
|
|
|
202
|
|
|
62
|
|
Williston Basin
|
|
131
|
|
|
76
|
|
|
7
|
|
|
6
|
|
Other
|
|
482
|
|
|
185
|
|
|
165
|
|
|
98
|
|
Total domestic
|
|
1,706
|
|
|
874
|
|
|
497
|
|
|
225
|
|
China:
|
|
12
|
|
|
6
|
|
|
—
|
|
|
—
|
|
Total
|
|
1,718
|
|
|
880
|
|
|
497
|
|
|
225
|
|
|
|
Undeveloped Acres Expiring
|
||||||||||||||||||||||||||||
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
||||||||||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||||
|
|
(In thousands)
|
||||||||||||||||||||||||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Anadarko Basin
|
|
42
|
|
|
21
|
|
|
43
|
|
|
28
|
|
|
13
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Arkoma Basin
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Uinta Basin
|
|
13
|
|
|
5
|
|
|
18
|
|
|
15
|
|
|
21
|
|
|
9
|
|
|
13
|
|
|
7
|
|
|
26
|
|
|
20
|
|
Williston Basin
|
|
1
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
96
|
|
|
53
|
|
|
26
|
|
|
13
|
|
|
18
|
|
|
12
|
|
|
12
|
|
|
9
|
|
|
1
|
|
|
—
|
|
Total
|
|
152
|
|
|
80
|
|
|
88
|
|
|
56
|
|
|
54
|
|
|
29
|
|
|
25
|
|
|
16
|
|
|
27
|
|
|
20
|
|
•
|
acquisition of seismic data;
|
•
|
location of wells;
|
•
|
size of drilling and spacing units or proration units;
|
•
|
number of wells that may be drilled in a unit;
|
•
|
unitization or pooling of oil and gas properties;
|
•
|
drilling, casing and cementing of wells;
|
•
|
issuance of permits in connection with exploration, drilling and production;
|
•
|
well production;
|
•
|
spill prevention plans;
|
•
|
protection of private and public surface and ground water supplies;
|
•
|
emissions reporting, permitting or limitations;
|
•
|
protection of endangered species and habitat;
|
•
|
occupational safety and health;
|
•
|
use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
|
•
|
surface usage and the restoration of properties upon which wells have been drilled;
|
•
|
calculation and disbursement of royalty payments and production taxes;
|
•
|
plugging and abandoning of wells;
|
•
|
transportation of production; and
|
•
|
export of natural gas.
|
•
|
assessing the environmental impact of seismic acquisition, drilling or construction activities;
|
•
|
the generation, storage, transportation and disposal of waste materials (including hazardous wastes) and flowback or produced water;
|
•
|
the emission of certain gases, including greenhouse gases, or other materials into the atmosphere;
|
•
|
the construction and placement of wells;
|
•
|
the investigation, monitoring, abandonment, reclamation and remediation of wells and other sites, including sites of former operations;
|
•
|
various environmental reporting and permitting requirements;
|
•
|
the development of emergency response and spill contingency plans;
|
•
|
disclosure of chemicals used in hydraulic fracturing;
|
•
|
health and safety of workers and the public; and
|
•
|
protection of private and public surface and ground water supplies.
|
•
|
the domestic and foreign supply of, and demand for, oil, natural gas and NGLs;
|
•
|
domestic and world-wide economic conditions;
|
•
|
the level and effect of trading in commodity futures markets, including commodity price speculators and others;
|
•
|
military, economic and political conditions in oil and gas producing regions;
|
•
|
the actions taken by OPEC and other foreign oil and gas producing nations, including the ability of members of OPEC to agree to and maintain production controls;
|
•
|
the impact of the U.S. dollar exchange rates on oil, natural gas and NGL prices;
|
•
|
the price and availability of, and demand for, alternative fuels;
|
•
|
weather conditions and climate change;
|
•
|
world-wide conservation measures;
|
•
|
technological advances affecting energy consumption and production;
|
•
|
changes in the price of oilfield services and technologies;
|
•
|
the price and level of foreign imports;
|
•
|
expansion of U.S. exports of oil, natural gas and/or NGLs;
|
•
|
the availability, proximity and capacity of transportation, processing, storage and refining facilities;
|
•
|
the costs of exploring for, developing, producing, transporting and marketing oil, natural gas and NGLs; and
|
•
|
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulations.
|
•
|
limit our access to sources of capital, such as equity and long-term debt;
|
•
|
cause us to delay or postpone capital projects;
|
•
|
cause us to lose certain leases because we fail to meet obligations of the leases prior to expiration;
|
•
|
reduce reserve estimates and the amount of products we can economically produce;
|
•
|
downgrade or other negative rating action with respect to our credit rating;
|
•
|
reduce revenues, income and cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; or
|
•
|
reduce the carrying value of our assets in our balance sheet through ceiling test impairments.
|
•
|
we generate less operational cash flow than we anticipate;
|
•
|
we are unable to sell non-strategic assets at acceptable prices;
|
•
|
our customers or working interest owners default on their obligations to us;
|
•
|
one or more of the lenders under our existing credit arrangements fails to honor its contractual obligation to lend to us;
|
•
|
investors limit funding or refrain from funding oil and gas companies; or
|
•
|
we are unable to access the capital markets at a time when we would like, or need, to raise capital.
|
•
|
incur additional indebtedness;
|
•
|
purchase or redeem our outstanding equity interests or subordinated debt;
|
•
|
make specified investments;
|
•
|
create liens;
|
•
|
sell assets;
|
•
|
engage in specified transactions with affiliates;
|
•
|
engage in sale-leaseback transactions; and
|
•
|
effect a merger or consolidation with or into other companies or a sale of all or substantially all of our properties or assets.
|
•
|
obtain future financing;
|
•
|
make needed capital expenditures;
|
•
|
plan for, or react to, changes in our business and the industry in which we operate;
|
•
|
compete with similar companies that have less debt;
|
•
|
withstand a future downturn in our business or the economy in general; or
|
•
|
conduct operations or otherwise take advantage of business opportunities that may arise.
|
•
|
the quality and quantity of available data;
|
•
|
the interpretation of that data;
|
•
|
the accuracy of various mandated economic assumptions and our expected development plan; and
|
•
|
the judgment of the persons preparing the estimate.
|
•
|
increases in the costs of, or shortages or delays in the availability of, drilling rigs, equipment and materials;
|
•
|
decreases in oil, natural gas and NGLs prices;
|
•
|
limited availability to us of financing on acceptable terms;
|
•
|
adverse weather conditions and changes in weather patterns;
|
•
|
unexpected operational events and drilling conditions;
|
•
|
abnormal pressure or irregularities in geologic formations;
|
•
|
surface access restrictions;
|
•
|
access to, and costs for, water needed in our waterflood project in the Greater Monument Butte Unit (GMBU);
|
•
|
the presence of underground sources of drinking water, previously unknown water or other extraction wells or endangered or threatened species;
|
•
|
embedded oilfield drilling and service tools;
|
•
|
equipment failures or accidents;
|
•
|
lack of necessary services or qualified personnel;
|
•
|
availability and timely issuance of required governmental permits and licenses;
|
•
|
loss of title and other title-related issues;
|
•
|
availability, costs and terms of contractual arrangements, such as leases, pipelines and related facilities to gather, process and compress, transport and market oil, natural gas and NGLs; and
|
•
|
compliance with, or changes in, environmental, tax and other laws and regulations.
|
•
|
fires and explosions;
|
•
|
blow-outs and cratering;
|
•
|
uncontrollable or unknown flows of oil, gas or well fluids;
|
•
|
pipe or cement failures and casing collapses;
|
•
|
pipeline or other facility ruptures and spills;
|
•
|
equipment malfunctions or operator error;
|
•
|
discharges of toxic gases;
|
•
|
induced seismic events;
|
•
|
environmental costs and liabilities due to our use, generation, handling and disposal of materials, including wastes, hydrocarbons and other chemicals; and
|
•
|
environmental damages caused by previous owners of property we purchase and lease.
|
•
|
injury or loss of life;
|
•
|
severe damage or destruction of property, natural resources and equipment;
|
•
|
pollution and other environmental damage;
|
•
|
investigatory and clean-up responsibilities;
|
•
|
regulatory investigation and penalties or lawsuits;
|
•
|
limitation on or suspension of our operations; and
|
•
|
repairs and remediation costs to resume operations.
|
•
|
restrictions for the protection of wildlife that regulate the time, place and manner in which we conduct operations;
|
•
|
the amounts, types and manner of substances and materials that may be released into the environment;
|
•
|
response to unexpected releases into the environment;
|
•
|
reports and permits concerning exploration, drilling, production and other operations;
|
•
|
the placement and spacing of wells;
|
•
|
cement and casing strength;
|
•
|
unitization and pooling of properties;
|
•
|
calculating royalties on oil and gas produced under federal and state leases; and
|
•
|
taxation.
|
•
|
the repeal of the percentage depletion allowance for oil and natural gas properties;
|
•
|
the elimination of current deductions for intangible drilling and development costs;
|
•
|
the elimination of the deduction for certain domestic production activities; and
|
•
|
an extension of the amortization period for certain geological and geophysical expenditures.
|
•
|
currency restrictions, exchange rate fluctuations, or other activities that disrupt markets and restrict payments or the movement of funds;
|
•
|
loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, piracy, acts of terrorism, insurrection, civil unrest and other political risks or other changes in government;
|
•
|
difficulties obtaining permits or governmental approvals as a foreign operator;
|
•
|
taxation policies, including increases in taxes and governmental royalties, retroactive tax claims and investment restrictions;
|
•
|
transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act and other anticorruption compliance laws and issues;
|
•
|
disruptions in international oil cargo shipping activities;
|
•
|
physical, digital, internal and external security breaches;
|
•
|
forced renegotiation of, unilateral changes to, or termination of contracts with, governmental entities and quasi- governmental agencies;
|
•
|
changes in laws and policies governing operations in China;
|
•
|
our limited ability to influence or control the operation or future development of non-operated properties;
|
•
|
the operator’s expertise or other labor problems;
|
•
|
cultural differences;
|
•
|
difficulties enforcing our rights against a governmental entity because of the doctrine of sovereign immunity and foreign sovereignty over our China operations; and
|
•
|
other uncertainties arising out of foreign government sovereignty over our China operations.
|
•
|
delay or denial of drilling permits;
|
•
|
shortening of lease terms or reduction in lease size;
|
•
|
restrictions on installation or operation of production, gathering or processing facilities;
|
•
|
restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water;
|
•
|
increased severance and/or other taxes;
|
•
|
cyber-attacks;
|
•
|
legal challenges or lawsuits;
|
•
|
negative publicity about our business or the oil and gas industry in general;
|
•
|
increased costs of doing business;
|
•
|
reduction in demand for our products; and
|
•
|
other adverse effects on our ability to develop our properties and expand production.
|
•
|
recoverable reserves;
|
•
|
exploration potential;
|
•
|
future oil, natural gas and NGL prices and their relevant differentials;
|
•
|
operating costs and production taxes; and
|
•
|
potential environmental and other liabilities.
|
Item 4.
|
Mine Safety Disclosures
|
Name
|
|
Age
|
|
Position
|
|
Total Years of Service with Newfield
|
Lee K. Boothby
|
|
56
|
|
President, Chief Executive Officer and Chairman of the Board
|
|
18
|
Lawrence S. Massaro
|
|
54
|
|
Executive Vice President and Chief Financial Officer
|
|
7
|
Gary D. Packer
|
|
55
|
|
Executive Vice President and Chief Operating Officer
|
|
22
|
George T. Dunn
|
|
60
|
|
Senior Vice President — Development
|
|
25
|
John H. Jasek
|
|
48
|
|
Senior Vice President — Operations
|
|
18
|
Stephen C. Campbell
|
|
49
|
|
Vice President — Investor Relations
|
|
18
|
George W. Fairchild, Jr.
|
|
50
|
|
Chief Accounting Officer
|
|
6
|
Timothy D. Yang
|
|
45
|
|
General Counsel and Corporate Secretary
|
|
3
|
Matthew R. Vezza
|
|
44
|
|
Regional Vice President
|
|
5
|
John D. Ford
|
|
58
|
|
Regional Vice President
|
|
1
|
Item 5.
|
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
|
High
|
|
Low
|
||||
2016:
|
|
|
|
|
||||
First Quarter
|
|
$
|
34.97
|
|
|
$
|
20.84
|
|
Second Quarter
|
|
44.79
|
|
|
30.88
|
|
||
Third Quarter
|
|
47.56
|
|
|
39.25
|
|
||
Fourth Quarter
|
|
50.00
|
|
|
37.17
|
|
||
2017:
|
|
|
|
|
||||
First Quarter
|
|
$
|
43.74
|
|
|
$
|
33.00
|
|
Second Quarter
|
|
37.61
|
|
|
27.22
|
|
||
Third Quarter
|
|
30.05
|
|
|
24.41
|
|
||
Fourth Quarter
|
|
33.33
|
|
|
27.77
|
|
||
2018:
|
|
|
|
|
||||
First Quarter (through February 15, 2018)
|
|
$
|
35.20
|
|
|
$
|
24.56
|
|
Period
|
|
Total Number of Shares Purchased
(1)
|
|
Average Price Paid per Share
|
|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
|
|
Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased under the Plans or Programs
|
|||
October 1 — October 31, 2017
|
|
4,313
|
|
|
$
|
29.40
|
|
|
—
|
|
—
|
November 1 — November 30, 2017
|
|
8,025
|
|
|
31.14
|
|
|
—
|
|
—
|
|
December 1 — December 31, 2017
|
|
6,873
|
|
|
31.35
|
|
|
—
|
|
—
|
|
Total
|
|
19,211
|
|
|
$
|
30.82
|
|
|
—
|
|
—
|
(1)
|
All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards and restricted stock units. These repurchases were not part of a publicly announced program to repurchase shares of our common stock.
|
•
|
$100 was invested in our common stock, the S&P 500 Index, the S&P Oil & Gas Exploration & Production Select Industry Index and our peer group on December 31, 2012, at the closing price on such date;
|
•
|
Investment in our peer group was weighted based on the stock market capitalization of each individual company within the peer group at the beginning of the period; and
|
•
|
Dividends were reinvested on the relevant payment dates.
|
Total Return Analysis
|
|
12/31/2012
|
|
12/31/2013
|
|
12/31/2014
|
|
12/31/2015
|
|
12/31/2016
|
|
12/31/2017
|
||||||||||||
Newfield Exploration Company
|
|
$
|
100.00
|
|
|
$
|
91.97
|
|
|
$
|
101.27
|
|
|
$
|
121.58
|
|
|
$
|
151.23
|
|
|
$
|
117.74
|
|
Peer Group
|
|
100.00
|
|
|
140.99
|
|
|
112.11
|
|
|
69.65
|
|
|
103.34
|
|
|
93.90
|
|
||||||
S&P Oil & Gas Exploration & Production Select Industry Index
|
|
100.00
|
|
|
128.15
|
|
|
90.38
|
|
|
57.80
|
|
|
80.23
|
|
|
72.96
|
|
||||||
S&P 500 Index - Total Returns
|
|
100.00
|
|
|
132.39
|
|
|
150.51
|
|
|
152.59
|
|
|
170.84
|
|
|
208.14
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
|
|
(In millions, except per share data)
|
||||||||||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Oil, gas and NGL revenues
(1)
|
|
$
|
1,767
|
|
|
$
|
1,472
|
|
|
$
|
1,557
|
|
|
$
|
2,288
|
|
|
$
|
1,857
|
|
|
Income (loss) from continuing operations
|
|
427
|
|
|
(1,230
|
)
|
|
(3,362
|
)
|
|
650
|
|
|
73
|
|
||||||
Net income (loss)
|
|
427
|
|
|
(1,230
|
)
|
|
(3,362
|
)
|
|
900
|
|
|
147
|
|
||||||
Earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
|
$
|
2.13
|
|
|
$
|
(6.36
|
)
|
|
$
|
(21.18
|
)
|
|
$
|
4.71
|
|
|
$
|
0.39
|
|
|
Earnings (loss) per share
|
|
2.13
|
|
|
(6.36
|
)
|
|
(21.18
|
)
|
|
6.52
|
|
|
0.94
|
|
||||||
Weighted-average number of shares outstanding for diluted earnings (loss) per share
|
|
200
|
|
|
193
|
|
|
159
|
|
|
138
|
|
|
136
|
|
||||||
Balance Sheet Data (at end of period):
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total assets
|
|
$
|
4,961
|
|
|
$
|
4,312
|
|
|
$
|
4,768
|
|
|
$
|
9,580
|
|
|
$
|
9,297
|
|
|
Long-term debt
|
|
2,434
|
|
|
2,431
|
|
|
2,467
|
|
|
2,874
|
|
|
3,670
|
|
(1)
|
Continuing operations only (excludes Malaysia, which was sold in February 2014).
|
|
2015
|
|
Price Variance
|
|
Production Variance
|
|
2016
|
|
Price Variance
|
|
Production Variance
|
|
2017
|
||||||||||||||
Domestic:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Crude oil and condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Price (per Bbl)
|
$
|
39.89
|
|
|
$
|
(3.50
|
)
|
|
|
|
$
|
36.39
|
|
|
$
|
9.63
|
|
|
|
|
$
|
46.02
|
|
||||
Production (MBbls)
|
21,346
|
|
|
|
|
(374
|
)
|
|
20,972
|
|
|
|
|
1,352
|
|
|
22,324
|
|
|||||||||
Crude oil and condensate revenues
|
$
|
852
|
|
|
$
|
(74
|
)
|
|
$
|
(15
|
)
|
|
$
|
763
|
|
|
$
|
215
|
|
|
$
|
50
|
|
|
$
|
1,028
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Price (per Mcf)
|
$
|
2.40
|
|
|
$
|
(0.22
|
)
|
|
|
|
$
|
2.18
|
|
|
$
|
0.52
|
|
|
|
|
$
|
2.70
|
|
||||
Production (Bcf)
|
116.3
|
|
|
|
|
13.6
|
|
|
129.9
|
|
|
|
|
(4.3
|
)
|
|
125.6
|
|
|||||||||
Natural gas revenues
|
$
|
279
|
|
|
$
|
(28
|
)
|
|
$
|
33
|
|
|
$
|
284
|
|
|
$
|
64
|
|
|
$
|
(9
|
)
|
|
$
|
339
|
|
Natural gas liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Price (per Bbl)
|
$
|
18.40
|
|
|
$
|
0.65
|
|
|
|
|
$
|
19.05
|
|
|
$
|
7.97
|
|
|
|
|
$
|
27.02
|
|
||||
Production (MBbls)
|
8,553
|
|
|
|
|
2,167
|
|
|
10,720
|
|
|
|
|
842
|
|
|
11,562
|
|
|||||||||
Natural gas liquids revenues
|
$
|
157
|
|
|
$
|
7
|
|
|
$
|
40
|
|
|
$
|
204
|
|
|
$
|
92
|
|
|
$
|
16
|
|
|
$
|
312
|
|
Total Domestic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Price (per BOE)
|
$
|
26.14
|
|
|
$
|
(2.68
|
)
|
|
|
|
$
|
23.46
|
|
|
$
|
7.16
|
|
|
|
|
$
|
30.62
|
|
||||
Production (MBOE)
|
49,277
|
|
|
|
|
4,067
|
|
|
53,344
|
|
|
|
|
1,473
|
|
|
54,817
|
|
|||||||||
Total domestic oil and gas revenues
|
$
|
1,288
|
|
|
$
|
(95
|
)
|
|
$
|
58
|
|
|
$
|
1,251
|
|
|
$
|
371
|
|
|
$
|
57
|
|
|
$
|
1,679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
China:
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Crude oil and condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Price (per Bbl)
|
$
|
48.50
|
|
|
$
|
(8.15
|
)
|
|
|
|
|
$
|
40.35
|
|
|
$
|
10.12
|
|
|
|
|
|
$
|
50.47
|
|
||
Production/liftings (MBbls)
|
5,399
|
|
|
|
|
|
(29
|
)
|
|
5,370
|
|
|
|
|
|
(3,658
|
)
|
|
1,712
|
|
|||||||
China oil and condensate revenues
|
$
|
262
|
|
|
$
|
(44
|
)
|
|
$
|
(1
|
)
|
|
$
|
217
|
|
|
$
|
17
|
|
|
$
|
(148
|
)
|
|
$
|
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Crude oil and condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Price (per Bbl)
|
$
|
41.63
|
|
|
$
|
(4.43
|
)
|
|
|
|
$
|
37.20
|
|
|
$
|
9.13
|
|
|
|
|
$
|
46.33
|
|
||||
Production/liftings (MBbls)
|
26,745
|
|
|
|
|
(403
|
)
|
|
26,342
|
|
|
|
|
(2,306
|
)
|
|
24,036
|
|
|||||||||
Crude oil and condensate revenues
|
$
|
1,114
|
|
|
$
|
(118
|
)
|
|
$
|
(16
|
)
|
|
$
|
980
|
|
|
$
|
232
|
|
|
$
|
(98
|
)
|
|
$
|
1,114
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Price (per Mcf)
|
$
|
2.40
|
|
|
$
|
(0.22
|
)
|
|
|
|
$
|
2.18
|
|
|
$
|
0.52
|
|
|
|
|
$
|
2.70
|
|
||||
Production (Bcf)
|
116.3
|
|
|
|
|
13.6
|
|
|
129.9
|
|
|
|
|
(4.3
|
)
|
|
125.6
|
|
|||||||||
Natural gas revenues
|
$
|
279
|
|
|
$
|
(28
|
)
|
|
$
|
33
|
|
|
$
|
284
|
|
|
$
|
64
|
|
|
$
|
(9
|
)
|
|
$
|
339
|
|
Natural gas liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Price (per Bbl)
|
$
|
18.40
|
|
|
$
|
0.65
|
|
|
|
|
$
|
19.05
|
|
|
$
|
7.97
|
|
|
|
|
$
|
27.02
|
|
||||
Production (MBbls)
|
8,553
|
|
|
|
|
2,167
|
|
|
10,720
|
|
|
|
|
842
|
|
|
11,562
|
|
|||||||||
Natural gas liquids revenues
|
$
|
157
|
|
|
$
|
7
|
|
|
$
|
40
|
|
|
$
|
204
|
|
|
$
|
92
|
|
|
$
|
16
|
|
|
$
|
312
|
|
Total consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Price (per BOE)
|
$
|
28.35
|
|
|
$
|
(3.35
|
)
|
|
|
|
$
|
25.00
|
|
|
$
|
6.22
|
|
|
|
|
$
|
31.22
|
|
||||
Production/liftings (MBOE)
|
54,676
|
|
|
|
|
4,038
|
|
|
58,714
|
|
|
|
|
(2,185
|
)
|
|
56,529
|
|
|||||||||
Total consolidated oil and gas revenues
|
$
|
1,550
|
|
|
$
|
(139
|
)
|
|
$
|
57
|
|
|
$
|
1,468
|
|
|
$
|
388
|
|
|
$
|
(91
|
)
|
|
$
|
1,765
|
|
(1)
|
Excludes natural gas produced and consumed in operations of
4.5
Bcf in
2017
,
5.3
Bcf in
2016
and
7.7
Bcf in
2015
.
|
(2)
|
Represents our net share of volumes sold regardless of when produced.
|
|
|
Unit-of-Production
|
|
Total Amount
|
||||||||||||||||||
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
||||||||||||||
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|||||||||||||
|
|
(Per BOE)
|
|
|
|
(In millions)
|
|
|
||||||||||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating
|
|
$
|
3.42
|
|
|
$
|
3.55
|
|
|
(4
|
)%
|
|
$
|
188
|
|
|
$
|
189
|
|
|
(1
|
)%
|
Transportation and processing
|
|
5.48
|
|
|
5.09
|
|
|
8
|
%
|
|
300
|
|
|
272
|
|
|
11
|
%
|
||||
Production and other taxes
|
|
1.16
|
|
|
0.77
|
|
|
50
|
%
|
|
64
|
|
|
41
|
|
|
54
|
%
|
||||
Depreciation, depletion and amortization
|
|
8.07
|
|
|
8.58
|
|
|
(6
|
)%
|
|
443
|
|
|
458
|
|
|
(3
|
)%
|
||||
General and administrative
|
|
3.54
|
|
|
3.84
|
|
|
(8
|
)%
|
|
194
|
|
|
205
|
|
|
(5
|
)%
|
||||
Ceiling test and other impairments
|
|
—
|
|
|
18.04
|
|
|
(100
|
)%
|
|
—
|
|
|
962
|
|
|
(100
|
)%
|
||||
Other
|
|
0.10
|
|
|
0.38
|
|
|
(74
|
)%
|
|
5
|
|
|
20
|
|
|
(73
|
)%
|
||||
Total operating expenses
|
|
21.77
|
|
|
40.25
|
|
|
(46
|
)%
|
|
1,194
|
|
|
2,147
|
|
|
(44
|
)%
|
||||
China:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating
|
|
$
|
15.79
|
|
|
$
|
10.31
|
|
|
54
|
%
|
|
$
|
27
|
|
|
$
|
55
|
|
|
(51
|
)%
|
Production and other taxes
|
|
0.18
|
|
|
0.15
|
|
|
23
|
%
|
|
—
|
|
|
1
|
|
|
(61
|
)%
|
||||
Depreciation, depletion and amortization
|
|
14.14
|
|
|
21.17
|
|
|
(33
|
)%
|
|
24
|
|
|
114
|
|
|
(79
|
)%
|
||||
General and administrative
|
|
3.79
|
|
|
1.43
|
|
|
>100%
|
|
|
6
|
|
|
8
|
|
|
(16
|
)%
|
||||
Ceiling test impairment
|
|
—
|
|
|
12.30
|
|
|
(100
|
)%
|
|
—
|
|
|
66
|
|
|
(100
|
)%
|
||||
Other
|
|
0.20
|
|
|
—
|
|
|
>100%
|
|
|
1
|
|
|
—
|
|
|
(9
|
)%
|
||||
Total operating expenses
|
|
34.10
|
|
|
45.36
|
|
|
(25
|
)%
|
|
58
|
|
|
244
|
|
|
(76
|
)%
|
||||
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating
|
|
$
|
3.80
|
|
|
$
|
4.16
|
|
|
(9
|
)%
|
|
$
|
215
|
|
|
$
|
244
|
|
|
(12
|
)%
|
Transportation and processing
|
|
5.31
|
|
|
4.62
|
|
|
15
|
%
|
|
300
|
|
|
272
|
|
|
11
|
%
|
||||
Production and other taxes
|
|
1.13
|
|
|
0.72
|
|
|
58
|
%
|
|
64
|
|
|
42
|
|
|
52
|
%
|
||||
Depreciation, depletion and amortization
|
|
8.25
|
|
|
9.74
|
|
|
(15
|
)%
|
|
467
|
|
|
572
|
|
|
(18
|
)%
|
||||
General and administrative
|
|
3.54
|
|
|
3.62
|
|
|
(2
|
)%
|
|
200
|
|
|
213
|
|
|
(6
|
)%
|
||||
Ceiling test and other impairments
|
|
—
|
|
|
17.51
|
|
|
(100
|
)%
|
|
—
|
|
|
1,028
|
|
|
(100
|
)%
|
||||
Other
|
|
0.10
|
|
|
0.35
|
|
|
(71
|
)%
|
|
6
|
|
|
20
|
|
|
(72
|
)%
|
||||
Total operating expenses
|
|
22.13
|
|
|
40.72
|
|
|
(46
|
)%
|
|
1,252
|
|
|
2,391
|
|
|
(48
|
)%
|
•
|
Lease operating expense per BOE decreased
4%
primarily due to an increased concentration of total production in STACK where operating costs are lower. Total lease operating expense was flat period over period due to increased production, higher well servicing costs in the Williston Basin and additional costs incurred to protect our wells against offset hydraulic fracturing operations by other operators in the Williston Basin, offset by the reduction of costs associated with the sale of our Texas assets in the third quarter of 2016.
|
•
|
Transportation and processing expense per BOE increased
8%
due to increased oil deficiency fees of $13 million in the Uinta Basin and higher utilization of oil pipelines in the STACK play, which allows us to transport oil to more favorable markets and thus receive a higher sales price.
|
•
|
Production and other taxes per BOE increased
50%
primarily due to higher commodity prices compared to 2016, combined with regulatory changes in Oklahoma that increased tax rates for certain wells effective July 2017 and December 2017.
|
•
|
Depreciation, depletion and amortization (DD&A) per BOE decreased
6%
primarily due to the impact of ceiling test impairments during the first half of 2016.
|
•
|
General and administrative expense (G&A)
decreased
5%
, primarily due to reduction in workforce and restructuring charges recorded in 2016. This decrease was partially offset by increased stock compensation expense due to accelerated recognition of expense related to changes made to our qualified retirement plan during
2017
. The following table presents information regarding G&A expenses for our domestic operations:
|
|
|
Unit-of-Production
|
|
Total Amount
|
||||||||||||||||||
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
||||||||||||||
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|||||||||||||
|
|
(Per BOE)
|
|
|
|
(In millions)
|
|
|
||||||||||||||
G&A expense (net of amounts capitalized)
|
|
$
|
3.54
|
|
|
$
|
3.84
|
|
|
(8
|
)%
|
|
$
|
194
|
|
|
$
|
205
|
|
|
(5
|
)%
|
Capitalized direct internal costs
|
|
1.18
|
|
|
1.31
|
|
|
(10
|
)%
|
|
65
|
|
|
70
|
|
|
(7
|
)%
|
||||
Gross G&A expense
|
|
4.72
|
|
|
5.15
|
|
|
(8
|
)%
|
|
259
|
|
|
275
|
|
|
(6
|
)%
|
||||
Other items affecting comparability:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Reduction in workforce and restructuring
(1)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.53
|
)
|
|
(94
|
)%
|
|
$
|
(2
|
)
|
|
$
|
(28
|
)
|
|
(94
|
)%
|
Total
|
|
4.69
|
|
|
4.62
|
|
|
1
|
%
|
|
257
|
|
|
247
|
|
|
4
|
%
|
(1)
|
Includes severance costs for workforce reductions, as well as office-lease abandonment and other organizational restructuring costs related to the consolidation of our Denver, Houston and Tulsa offices into our headquarters in The Woodlands, Texas. See Note
17
, "
Restructuring Costs
," to our consolidated financial statements in
Item 8
of this report for additional details regarding our restructuring activities.
|
•
|
During
2017
, no ceiling test impairments were required. During 2016, we recorded ceiling test impairments of
$962 million
due to a net decrease in the discounted value of our proved reserves.
|
•
|
Other operating expense decreased $15 million primarily due to the settlement of a lawsuit against the Company during the third quarter of 2016. See Note
12
, "Commitments and Contingencies," to our consolidated financial statements in Item 8 of this report.
|
•
|
Lease operating expense per BOE increased
54%
primarily due to lower lifting volumes and higher production handling fees per BOE, which increase as oil prices increase. Total lease operating expense decreased
51%
due to lower lifting volumes.
|
•
|
DD&A expense per BOE
decreased
33%
primarily due to a reduction of our DD&A rate as a result of the ceiling test impairments during 2015 and the first half of 2016.
|
•
|
During 2017, no ceiling test impairments were required. During the first half of 2016, we recorded non-cash ceiling test impairments of
$66 million
.
|
|
|
Unit-of-Production
|
|
Total Amount
|
||||||||||||||||||
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
||||||||||||||
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|||||||||||||
|
|
(Per BOE)
|
|
|
|
(In millions)
|
|
|
|
|||||||||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating
|
|
$
|
3.55
|
|
|
$
|
4.69
|
|
|
(24
|
)%
|
|
$
|
189
|
|
|
$
|
231
|
|
|
(18
|
)%
|
Transportation and processing
|
|
5.09
|
|
|
4.29
|
|
|
19
|
%
|
|
272
|
|
|
212
|
|
|
28
|
%
|
||||
Production and other taxes
|
|
0.77
|
|
|
0.91
|
|
|
(15
|
)%
|
|
41
|
|
|
45
|
|
|
(8
|
)%
|
||||
Depreciation, depletion and amortization
|
|
8.58
|
|
|
15.31
|
|
|
(44
|
)%
|
|
458
|
|
|
754
|
|
|
(39
|
)%
|
||||
General and administrative
|
|
3.84
|
|
|
4.80
|
|
|
(20
|
)%
|
|
205
|
|
|
237
|
|
|
(13
|
)%
|
||||
Ceiling test and other impairments
|
|
18.04
|
|
|
97.13
|
|
|
(81
|
)%
|
|
962
|
|
|
4,786
|
|
|
(80
|
)%
|
||||
Other
|
|
0.38
|
|
|
0.19
|
|
|
100
|
%
|
|
20
|
|
|
9
|
|
|
>100%
|
|
||||
Total operating expenses
|
|
40.25
|
|
|
127.32
|
|
|
(68
|
)%
|
|
2,147
|
|
|
6,274
|
|
|
(66
|
)%
|
||||
China:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating
|
|
$
|
10.31
|
|
|
$
|
10.07
|
|
|
2
|
%
|
|
$
|
55
|
|
|
$
|
54
|
|
|
1
|
%
|
Production and other taxes
|
|
0.15
|
|
|
0.15
|
|
|
—
|
%
|
|
1
|
|
|
1
|
|
|
(2
|
)%
|
||||
Depreciation, depletion and amortization
|
|
21.17
|
|
|
30.09
|
|
|
(30
|
)%
|
|
114
|
|
|
163
|
|
|
(30
|
)%
|
||||
General and administrative
|
|
1.43
|
|
|
1.31
|
|
|
9
|
%
|
|
8
|
|
|
7
|
|
|
9
|
%
|
||||
Ceiling test impairment
|
|
12.30
|
|
|
21.84
|
|
|
(44
|
)%
|
|
66
|
|
|
118
|
|
|
(44
|
)%
|
||||
Other
|
|
—
|
|
|
0.21
|
|
|
(100
|
)%
|
|
—
|
|
|
1
|
|
|
(100
|
)%
|
||||
Total operating expenses
|
|
45.36
|
|
|
63.67
|
|
|
(29
|
)%
|
|
244
|
|
|
344
|
|
|
(29
|
)%
|
||||
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating
|
|
$
|
4.16
|
|
|
$
|
5.22
|
|
|
(20
|
)%
|
|
$
|
244
|
|
|
$
|
285
|
|
|
(14
|
)%
|
Transportation and processing
|
|
4.62
|
|
|
3.87
|
|
|
19
|
%
|
|
272
|
|
|
212
|
|
|
28
|
%
|
||||
Production and other taxes
|
|
0.72
|
|
|
0.84
|
|
|
(14
|
)%
|
|
42
|
|
|
46
|
|
|
(8
|
)%
|
||||
Depreciation, depletion and amortization
|
|
9.74
|
|
|
16.77
|
|
|
(42
|
)%
|
|
572
|
|
|
917
|
|
|
(38
|
)%
|
||||
General and administrative
|
|
3.62
|
|
|
4.46
|
|
|
(19
|
)%
|
|
213
|
|
|
244
|
|
|
(13
|
)%
|
||||
Ceiling test and other impairments
|
|
17.51
|
|
|
89.69
|
|
|
(80
|
)%
|
|
1,028
|
|
|
4,904
|
|
|
(79
|
)%
|
||||
Other
|
|
0.35
|
|
|
0.19
|
|
|
84
|
%
|
|
20
|
|
|
10
|
|
|
98
|
%
|
||||
Total operating expenses
|
|
40.72
|
|
|
121.04
|
|
|
(66
|
)%
|
|
2,391
|
|
|
6,618
|
|
|
(64
|
)%
|
•
|
Total LOE decreased
18%
despite an 8% increase in total production due to our focus on cost-reduction initiatives in all basins. On a per BOE basis, LOE was
24%
lower due to successful cost reduction efforts combined with our focused growth in the Anadarko Basin, which has lower operating costs than our other basins.
|
•
|
Transportation and processing expense per BOE increased
19%
primarily due to an increase in NGL and natural gas volumes produced of 25% and 12%, respectively. Additionally, oil transportation costs increased due to deficiency fees
|
•
|
Production and other taxes decreased
15%
per BOE year over year primarily due to our 2016 development activities occurring in areas with lower production tax rates.
|
•
|
DD&A expense per BOE decreased
44%
primarily due to the impact of ceiling test impairments of $4.8 billion recorded in 2015 and $962 million recorded in the first half of 2016.
|
•
|
G&A decreased
13%
. G&A expenses for both years included capitalized direct internal costs and costs associated with workforce reductions and organizational restructuring. Excluding these items that affect comparability, gross G&A costs decreased
11%
year over year, primarily due to cost savings initiatives including a more than 15% reduction of our workforce. The following table presents information regarding G&A expenses for our domestic operations:
|
|
|
Unit-of-Production
|
|
Total Amount
|
||||||||||||||||||
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
|
Year Ended
December 31,
|
|
Percentage
Increase
(Decrease)
|
||||||||||||||
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|||||||||||||
|
|
(Per BOE)
|
|
|
|
(In millions)
|
|
|
||||||||||||||
G&A expense (net of amounts capitalized)
|
|
$
|
3.84
|
|
|
$
|
4.80
|
|
|
(20
|
)%
|
|
$
|
205
|
|
|
$
|
237
|
|
|
(13
|
)%
|
Capitalized direct internal costs
|
|
1.31
|
|
|
1.52
|
|
|
(14
|
)%
|
|
70
|
|
|
75
|
|
|
(7
|
)%
|
||||
Gross G&A expense
|
|
5.15
|
|
|
6.32
|
|
|
(19
|
)%
|
|
275
|
|
|
312
|
|
|
(12
|
)%
|
||||
Other items affecting comparability:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Reduction in workforce and restructuring
(1)
|
|
$
|
(0.53
|
)
|
|
$
|
(0.77
|
)
|
|
(32
|
)%
|
|
$
|
(28
|
)
|
|
$
|
(39
|
)
|
|
(27
|
)%
|
SVAP program
(2)
|
|
—
|
|
|
0.05
|
|
|
(100
|
)%
|
|
—
|
|
|
3
|
|
|
(100
|
)%
|
||||
Total
|
|
4.62
|
|
|
5.60
|
|
|
(17
|
)%
|
|
247
|
|
|
276
|
|
|
(11
|
)%
|
(1)
|
Includes severance costs for workforce reductions, as well as office-lease abandonment and other organizational restructuring costs related to the consolidation of our Denver, Houston and Tulsa offices into our headquarters in The Woodlands, Texas. See Note
17
, "
Restructuring Costs
," to our consolidated financial statements in
Item 8
of this report for additional details regarding our restructuring activities.
|
(2)
|
SVAP program decrease is associated with the decrease in the estimated fair value of the liability for our Stockholder Value Appreciation Program (SVAP), which ended December 31, 2015.
|
•
|
During
2016
, we recorded ceiling test impairments of $962 million due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 15% decrease in crude oil SEC pricing and a 4% decrease in natural gas SEC pricing since
December 31, 2015
. During 2015, we recorded ceiling test impairments of $4.8 billion due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 47% decrease in crude oil SEC pricing and a 40% decrease in natural gas SEC pricing since December 31, 2014. These commodity price decreases were partially offset by the impact of current service cost reductions on our cash flow estimates.
|
•
|
Other operating expense increased $11 million primarily due to the settlement of a lawsuit against the Company during the third quarter of 2016. See Note
12
, "
Commitments and Contingencies
," to our consolidated financial statements in Item 8 of this report.
|
•
|
Lease operating expense remained flat year over year.
|
•
|
DD&A expense per BOE decreased
30%
primarily due to a reduction of our DD&A rate as a result of the ceiling test impairments during the first half of 2016.
|
•
|
During 2016, we recorded non-cash ceiling test impairments of $66 million due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 15% decrease in crude oil SEC pricing since December 31, 2015.
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
Gross interest expense:
|
|
|
|
|
|
|
||||||
Credit arrangements
|
|
$
|
9
|
|
|
$
|
14
|
|
|
$
|
10
|
|
Senior notes
|
|
140
|
|
|
140
|
|
|
132
|
|
|||
Senior subordinated notes
|
|
—
|
|
|
—
|
|
|
21
|
|
|||
Other
|
|
1
|
|
|
—
|
|
|
1
|
|
|||
Total gross interest expense
|
|
150
|
|
|
154
|
|
|
164
|
|
|||
Capitalized interest
|
|
(61
|
)
|
|
(51
|
)
|
|
(33
|
)
|
|||
Net interest expense
|
|
$
|
89
|
|
|
$
|
103
|
|
|
$
|
131
|
|
|
|
Positions Settled in 2017
|
|
Positions Settling in 2018 and Thereafter
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
Net derivative asset (liability) at December 31, 2016
|
|
$
|
(22
|
)
|
|
$
|
(3
|
)
|
|
$
|
(25
|
)
|
Change in fair value of settled positions
|
|
58
|
|
|
—
|
|
|
58
|
|
|||
Realized settlements
|
|
(36
|
)
|
|
—
|
|
|
(36
|
)
|
|||
Change in fair value of outstanding positions
|
|
—
|
|
|
(105
|
)
|
|
(105
|
)
|
|||
Total unrealized gain (loss)
|
|
22
|
|
|
(105
|
)
|
|
(83
|
)
|
|||
Net derivative asset (liability) at December 31, 2017
|
|
$
|
—
|
|
|
$
|
(108
|
)
|
|
$
|
(108
|
)
|
|
|
Positions Settled in 2016
|
|
Positions Settling in 2017 and Thereafter
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
Net derivative asset (liability) at December 31, 2015
|
|
$
|
272
|
|
|
$
|
95
|
|
|
$
|
367
|
|
Change in fair value of settled positions
|
|
(71
|
)
|
|
—
|
|
|
(71
|
)
|
|||
Realized settlements
|
|
(201
|
)
|
|
—
|
|
|
(201
|
)
|
|||
Change in fair value of outstanding positions
|
|
—
|
|
|
(120
|
)
|
|
(120
|
)
|
|||
Total unrealized gain (loss)
|
|
(272
|
)
|
|
(120
|
)
|
|
(392
|
)
|
|||
Net derivative asset (liability) at December 31, 2016
|
|
$
|
—
|
|
|
$
|
(25
|
)
|
|
$
|
(25
|
)
|
•
|
Beginning January 1, 2018, our U.S. income will be taxed at the 21% federal corporate rate. Further, we were required to recognize the effect of this rate change on our deferred tax assets and liabilities in 2017, the period the tax rate change was enacted. We maintain a full valuation allowance on our net deferred tax asset balance, therefore the rate change resulted in a non-cash decrease to the deferred tax asset and a corresponding and offsetting decrease in the valuation allowance balances of approximately $199 million for the quarter ended December 31, 2017.
|
•
|
The Tax Act also repealed the corporate alternative minimum tax (AMT) for tax years beginning January 1, 2018, and provides that existing AMT credit carryovers are refundable beginning in 2019. We had approximately $42 million of AMT credit carryovers at the end of 2017 that are expected to be fully refunded between 2019 and 2022. The valuation allowance related to this deferred tax asset was released and a noncurrent receivable was established, which resulted in a tax benefit of $42 million for the quarter ended December 31, 2017.
|
•
|
Further, the Tax Act modified the taxation of foreign earnings and the utilization of foreign tax credits (FTCs). As of December 31, 3017, we had $408 million of FTCs that have no value under the Tax Act which resulted in a non-cash reduction to the deferred tax asset and a corresponding and offsetting decrease in the valuation allowance.
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(In millions)
|
||||||
Alternative Minimum Tax credits
|
$
|
(61
|
)
|
|
$
|
(13
|
)
|
Carryback of net operating losses
|
(17
|
)
|
|
—
|
|
||
Provision to return adjustment
|
(1
|
)
|
|
—
|
|
||
China in-country tax expense (credits)
|
1
|
|
|
22
|
|
||
Current income tax provision (benefit)
|
(78
|
)
|
|
9
|
|
||
|
|
|
|
||||
Oklahoma state deferred tax
|
37
|
|
|
13
|
|
||
Deferred tax expense (benefit)
|
37
|
|
|
13
|
|
||
Total income tax provision (benefit)
|
$
|
(41
|
)
|
|
$
|
22
|
|
•
|
spent
$1.156 billion
for capital additions to oil and gas properties, an increase of $288 million compared to the same period of 2016 due to increased drilling activity in the Anadarko Basin;
|
•
|
acquired additional interest in oil and gas properties of $110 million;
|
•
|
divested
$72 million
of non-strategic domestic assets;
|
•
|
redeemed a short-term certificate of deposit of $25 million; and
|
•
|
divested our interest in the Bohai Bay field in China for approximately
$32 million
, including customary post-closing adjustments.
|
•
|
issued 25.3 million additional shares of common stock through a public equity offering and received net proceeds of approximately $815 million, which we used primarily to repay all borrowings under our credit facility and money market lines of credit; and
|
•
|
issued $700 million 5⅜% Senior Notes due 2026 through a public debt offering and received net proceeds of $691 million in March 2015. In April 2015, we used the proceeds and cash on hand to redeem our $700 million aggregate principal of our 6⅞% Senior Subordinated Notes due 2020.
|
|
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
||||||||||||||
|
|
(In millions)
|
||||||||||||||||||||||||||
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
5¾% Senior Notes due 2022
|
|
$
|
750
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
750
|
|
|
$
|
—
|
|
5⅝% Senior Notes due 2024
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,000
|
|
|||||||
5
⅜% Senior Notes due 2026
|
|
700
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
700
|
|
|||||||
Total long-term debt
|
|
2,450
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
750
|
|
|
1,700
|
|
|||||||
Other obligations
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Interest payments
|
|
908
|
|
|
137
|
|
|
137
|
|
|
137
|
|
|
137
|
|
|
116
|
|
|
244
|
|
|||||||
Asset retirement obligations
|
|
133
|
|
|
3
|
|
|
5
|
|
|
46
|
|
|
6
|
|
|
2
|
|
|
71
|
|
|||||||
Operating leases and other
(2)
|
|
181
|
|
|
67
|
|
|
37
|
|
|
29
|
|
|
25
|
|
|
6
|
|
|
17
|
|
|||||||
Firm transportation
|
|
336
|
|
|
79
|
|
|
78
|
|
|
31
|
|
|
21
|
|
|
21
|
|
|
106
|
|
|||||||
Total other obligations
|
|
1,558
|
|
|
286
|
|
|
257
|
|
|
243
|
|
|
189
|
|
|
145
|
|
|
438
|
|
|||||||
Total contractual obligations
|
|
$
|
4,008
|
|
|
$
|
286
|
|
|
$
|
257
|
|
|
$
|
243
|
|
|
$
|
189
|
|
|
$
|
895
|
|
|
$
|
2,138
|
|
(1)
|
Excludes assets and liabilities associated with our derivative contracts, which are dependent on the commodity price at the time of the contract settlement. For a discussion regarding our derivative contracts, see Note
4
, "
Derivative Financial Instruments
," to our consolidated financial statements in Item 8 of this report.
|
(2)
|
Includes agreements for office space, drilling rigs and other equipment, as well as certain service contracts. The majority of these obligations relate to contracts for office space and drilling rigs and are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be less than the gross obligation disclosed.
|
|
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|||||||
Oil (MBbls)
|
|
58,951
|
|
|
12,220
|
|
|
11,315
|
|
|
8,136
|
|
|
5,840
|
|
|
5,840
|
|
|
15,600
|
|
|
|
|
|
NYMEX Contract Price Per Bbl
|
|||||||||||||||
|
|
|
|
|
|
|
|
Collars
|
|||||||||||
Period and Type of Instrument
|
|
Volume in MBbls
|
|
Swaps
(Weighted Average) |
|
Puts (Weighted Average)
|
|
Floors
(Weighted Average) |
|
Ceilings
(Weighted Average) |
|||||||||
2018:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Swaptions
|
|
—
|
|
|
$
|
59.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fixed-price swaps
|
|
11,711
|
|
|
54.48
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Fixed-price swaps with sold puts
|
|
644
|
|
|
|
|
|
|
|
|
|
||||||||
Fixed-price swaps
|
|
|
|
56.78
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Sold puts
|
|
|
|
—
|
|
|
44.00
|
|
|
—
|
|
|
—
|
|
|||||
Collars
|
|
1,274
|
|
|
—
|
|
|
—
|
|
|
50.59
|
|
|
56.70
|
|
||||
Collars with sold puts:
|
|
4,941
|
|
|
|
|
|
|
|
|
|
||||||||
Collars
|
|
|
|
—
|
|
|
—
|
|
|
48.65
|
|
|
56.44
|
|
|||||
Sold puts
|
|
|
|
—
|
|
|
39.65
|
|
|
—
|
|
|
—
|
|
|||||
2019:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Collars with sold puts:
|
|
10,566
|
|
|
|
|
|
|
|
|
|
||||||||
Collars
|
|
|
|
—
|
|
|
—
|
|
|
50.59
|
|
|
57.13
|
|
|||||
Sold puts
|
|
|
|
—
|
|
|
40.60
|
|
|
—
|
|
|
—
|
|
Period and Type of Instrument
|
|
|
|
NYMEX Contract Price Per MMBtu
|
||||||||||||||||
|
|
|
|
|
|
Collars
|
||||||||||||||
Volume in
MMMBtus
|
|
Swaps
(Weighted
Average)
|
|
Puts (Weighted Average)
|
|
Floors (Weighted
Average)
|
|
Ceilings (Weighted
Average)
|
||||||||||||
2018:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed-price swaps
|
|
40,330
|
|
|
$
|
2.99
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Fixed-price swaps with sold puts
|
|
14,680
|
|
|
|
|
|
|
|
|
|
|||||||||
Fixed-price swaps
|
|
|
|
3.00
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Sold puts
|
|
|
|
—
|
|
|
2.62
|
|
|
|
|
|
||||||||
Collars
|
|
11,700
|
|
|
—
|
|
|
—
|
|
|
3.02
|
|
|
3.49
|
|
|||||
Collars with sold puts
|
|
6,420
|
|
|
|
|
|
|
|
|
|
|||||||||
Collars
|
|
|
|
—
|
|
|
—
|
|
|
2.87
|
|
|
3.32
|
|
||||||
Sold puts
|
|
|
|
—
|
|
|
2.30
|
|
|
—
|
|
|
—
|
|
||||||
2019:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed-price swaps
|
|
3,650
|
|
|
2.91
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Collars
|
|
9,000
|
|
|
—
|
|
|
—
|
|
|
3.00
|
|
|
3.47
|
|
Period and Type of Instrument
|
|
|
|
Mont Belvieu Contract Price Per Gallon
|
||||
Volume in MBbls
|
|
Swaps
(Weighted
Average)
|
||||||
2018:
|
|
|
|
|
||||
Fixed-price swaps
|
|
1,394
|
|
|
$
|
0.81
|
|
|
Page
|
|
|
|
Lee K. Boothby
|
|
Lawrence S. Massaro
|
Chairman, President and Chief Executive Officer
|
|
Executive Vice President and Chief Financial Officer
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
ASSETS
|
||||||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
326
|
|
|
$
|
555
|
|
Short-term investments
|
|
—
|
|
|
25
|
|
||
Accounts receivable, net
|
|
292
|
|
|
232
|
|
||
Inventories
|
|
15
|
|
|
16
|
|
||
Derivative assets
|
|
15
|
|
|
75
|
|
||
Other current assets
|
|
98
|
|
|
46
|
|
||
Total current assets
|
|
746
|
|
|
949
|
|
||
Oil and gas properties, net — full cost method ($1,200 and $1,238 were excluded from amortization at December 31, 2017 and 2016, respectively)
|
|
3,931
|
|
|
3,140
|
|
||
Other property and equipment, net
|
|
168
|
|
|
167
|
|
||
Derivative assets
|
|
1
|
|
|
—
|
|
||
Long-term investments
|
|
24
|
|
|
19
|
|
||
Restricted cash
|
|
40
|
|
|
25
|
|
||
Other assets
|
|
51
|
|
|
12
|
|
||
Total assets
|
|
$
|
4,961
|
|
|
$
|
4,312
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
46
|
|
|
$
|
33
|
|
Accrued liabilities
|
|
591
|
|
|
498
|
|
||
Advances from joint owners
|
|
80
|
|
|
54
|
|
||
Asset retirement obligations
|
|
3
|
|
|
2
|
|
||
Derivative liabilities
|
|
98
|
|
|
97
|
|
||
Total current liabilities
|
|
818
|
|
|
684
|
|
||
Other liabilities
|
|
69
|
|
|
63
|
|
||
Derivative liabilities
|
|
26
|
|
|
3
|
|
||
Long-term debt
|
|
2,434
|
|
|
2,431
|
|
||
Asset retirement obligations
|
|
130
|
|
|
154
|
|
||
Deferred taxes
|
|
76
|
|
|
39
|
|
||
Total long-term liabilities
|
|
2,735
|
|
|
2,690
|
|
||
Commitments and contingencies (Note 12)
|
|
|
|
|
||||
Stockholders' equity:
|
|
|
|
|
||||
Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)
|
|
—
|
|
|
—
|
|
||
Common stock ($0.01 par value, 300,000,000 shares authorized at December 31, 2017 and 2016; 201,363,345 and 200,150,392 shares issued at December 31, 2017 and 2016, respectively)
|
|
2
|
|
|
2
|
|
||
Additional paid-in capital
|
|
3,303
|
|
|
3,247
|
|
||
Treasury stock (at cost, 1,658,476 and 1,195,809 shares at December 31, 2017 and 2016, respectively)
|
|
(59
|
)
|
|
(44
|
)
|
||
Accumulated other comprehensive income (loss)
|
|
—
|
|
|
(2
|
)
|
||
Retained earnings (deficit)
|
|
(1,838
|
)
|
|
(2,265
|
)
|
||
Total stockholders' equity
|
|
1,408
|
|
|
938
|
|
||
Total liabilities and stockholders' equity
|
|
$
|
4,961
|
|
|
$
|
4,312
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Oil, gas and NGL revenues
|
|
$
|
1,767
|
|
|
$
|
1,472
|
|
|
$
|
1,557
|
|
|
|
|
|
|
|
|
||||||
Operating expenses:
|
|
|
|
|
|
|
||||||
Lease operating
|
|
215
|
|
|
244
|
|
|
285
|
|
|||
Transportation and processing
|
|
300
|
|
|
272
|
|
|
212
|
|
|||
Production and other taxes
|
|
64
|
|
|
42
|
|
|
46
|
|
|||
Depreciation, depletion and amortization
|
|
467
|
|
|
572
|
|
|
917
|
|
|||
General and administrative
|
|
200
|
|
|
213
|
|
|
244
|
|
|||
Ceiling test and other impairments
|
|
—
|
|
|
1,028
|
|
|
4,904
|
|
|||
Other
|
|
6
|
|
|
20
|
|
|
10
|
|
|||
Total operating expenses
|
|
1,252
|
|
|
2,391
|
|
|
6,618
|
|
|||
Income (loss) from operations
|
|
515
|
|
|
(919
|
)
|
|
(5,061
|
)
|
|||
|
|
|
|
|
|
|
||||||
Other income (expense):
|
|
|
|
|
|
|
||||||
Interest expense
|
|
(150
|
)
|
|
(154
|
)
|
|
(164
|
)
|
|||
Capitalized interest
|
|
61
|
|
|
51
|
|
|
33
|
|
|||
Commodity derivative income (expense)
|
|
(47
|
)
|
|
(191
|
)
|
|
259
|
|
|||
Other, net
|
|
7
|
|
|
5
|
|
|
(14
|
)
|
|||
Total other income (expense)
|
|
(129
|
)
|
|
(289
|
)
|
|
114
|
|
|||
|
|
|
|
|
|
|
||||||
Income (loss) before income taxes
|
|
386
|
|
|
(1,208
|
)
|
|
(4,947
|
)
|
|||
|
|
|
|
|
|
|
||||||
Income tax provision (benefit):
|
|
|
|
|
|
|
||||||
Current
|
|
(78
|
)
|
|
9
|
|
|
17
|
|
|||
Deferred
|
|
37
|
|
|
13
|
|
|
(1,602
|
)
|
|||
Total income tax provision (benefit)
|
|
(41
|
)
|
|
22
|
|
|
(1,585
|
)
|
|||
Net income (loss)
|
|
$
|
427
|
|
|
$
|
(1,230
|
)
|
|
$
|
(3,362
|
)
|
|
|
|
|
|
|
|
||||||
Earnings (loss) per share:
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
2.14
|
|
|
$
|
(6.36
|
)
|
|
$
|
(21.18
|
)
|
Diluted
|
|
$
|
2.13
|
|
|
$
|
(6.36
|
)
|
|
$
|
(21.18
|
)
|
|
|
|
|
|
|
|
||||||
Weighted-average number of shares outstanding for basic earnings
(loss) per share |
|
199
|
|
|
193
|
|
|
159
|
|
|||
|
|
|
|
|
|
|
||||||
Weighted-average number of shares outstanding for diluted earnings
(loss) per share |
|
200
|
|
|
193
|
|
|
159
|
|
|||
|
|
|
|
|
|
|
||||||
Comprehensive income (loss):
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
427
|
|
|
$
|
(1,230
|
)
|
|
$
|
(3,362
|
)
|
Other comprehensive income (loss), net of tax
|
|
2
|
|
|
—
|
|
|
(1
|
)
|
|||
Comprehensive income (loss)
|
|
$
|
429
|
|
|
$
|
(1,230
|
)
|
|
$
|
(3,363
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
427
|
|
|
$
|
(1,230
|
)
|
|
$
|
(3,362
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
|
467
|
|
|
572
|
|
|
917
|
|
|||
Deferred tax provision (benefit)
|
|
37
|
|
|
13
|
|
|
(1,602
|
)
|
|||
Stock-based compensation
|
|
34
|
|
|
22
|
|
|
25
|
|
|||
Unrealized (gain) loss on derivative contracts
|
|
83
|
|
|
392
|
|
|
246
|
|
|||
Ceiling test and other impairments
|
|
—
|
|
|
1,028
|
|
|
4,904
|
|
|||
Other, net
|
|
14
|
|
|
13
|
|
|
43
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable
|
|
(60
|
)
|
|
22
|
|
|
83
|
|
|||
Increase (decrease) in accounts payable and accrued liabilities
|
|
27
|
|
|
(3
|
)
|
|
(45
|
)
|
|||
Other items, net
|
|
(77
|
)
|
|
(3
|
)
|
|
—
|
|
|||
Net cash provided by (used in) operating activities
|
|
952
|
|
|
826
|
|
|
1,209
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Additions to oil and gas properties
|
|
(1,156
|
)
|
|
(868
|
)
|
|
(1,607
|
)
|
|||
Acquisitions of oil and gas properties
|
|
(110
|
)
|
|
(486
|
)
|
|
(125
|
)
|
|||
Proceeds from sales of oil and gas properties
|
|
96
|
|
|
405
|
|
|
90
|
|
|||
Additions to other property and equipment
|
|
(23
|
)
|
|
(17
|
)
|
|
(13
|
)
|
|||
Proceeds from insurance settlement, net
|
|
—
|
|
|
—
|
|
|
57
|
|
|||
Redemptions of investments
|
|
50
|
|
|
—
|
|
|
—
|
|
|||
Purchases of investments
|
|
(25
|
)
|
|
(25
|
)
|
|
—
|
|
|||
Net cash provided by (used in) investing activities
|
|
(1,168
|
)
|
|
(991
|
)
|
|
(1,598
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
Proceeds from borrowings under credit arrangements
|
|
—
|
|
|
536
|
|
|
1,908
|
|
|||
Repayments of borrowings under credit arrangements
|
|
—
|
|
|
(575
|
)
|
|
(2,315
|
)
|
|||
Proceeds from issuance of senior notes
|
|
—
|
|
|
—
|
|
|
691
|
|
|||
Repayment of senior subordinated notes
|
|
—
|
|
|
—
|
|
|
(700
|
)
|
|||
Debt issue costs
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||
Proceeds from issuances of common stock, net
|
|
3
|
|
|
779
|
|
|
819
|
|
|||
Purchases of treasury stock, net
|
|
(15
|
)
|
|
(22
|
)
|
|
(12
|
)
|
|||
Other
|
|
(1
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|||
Net cash provided by (used in) financing activities
|
|
(13
|
)
|
|
715
|
|
|
380
|
|
|||
Increase (decrease) in cash and cash equivalents
|
|
(229
|
)
|
|
550
|
|
|
(9
|
)
|
|||
Cash and cash equivalents, beginning of period
|
|
555
|
|
|
5
|
|
|
14
|
|
|||
Cash and cash equivalents, end of period
|
|
$
|
326
|
|
|
$
|
555
|
|
|
$
|
5
|
|
|
|
Common Stock
|
|
Treasury Stock
|
|
Additional
Paid-in Capital |
|
Retained
Earnings (Deficit) |
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total
Stockholders' Equity |
|||||||||||||||||||
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
||||||||||||||||||||||
Balance, December 31, 2014
|
|
137.6
|
|
|
$
|
1
|
|
|
(0.3
|
)
|
|
$
|
(10
|
)
|
|
$
|
1,576
|
|
|
$
|
2,327
|
|
|
$
|
(1
|
)
|
|
$
|
3,893
|
|
|
Issuances of common stock
|
|
26.5
|
|
|
1
|
|
|
|
|
|
|
818
|
|
|
|
|
|
|
819
|
|
|||||||||||
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
42
|
|
|||||||||||||
Treasury stock, net
|
|
|
|
|
|
(0.3
|
)
|
|
(12
|
)
|
|
—
|
|
|
|
|
|
|
(12
|
)
|
|||||||||||
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
(3,362
|
)
|
|
|
|
(3,362
|
)
|
|||||||||||||
Other comprehensive income (loss), net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
(1
|
)
|
|||||||||||||
Balance, December 31, 2015
|
|
164.1
|
|
|
2
|
|
|
(0.6
|
)
|
|
(22
|
)
|
|
2,436
|
|
|
(1,035
|
)
|
|
(2
|
)
|
|
1,379
|
|
|||||||
Issuances of common stock
|
|
36.1
|
|
|
—
|
|
|
|
|
|
|
779
|
|
|
|
|
|
|
779
|
|
|||||||||||
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
32
|
|
|||||||||||||
Treasury stock, net
|
|
|
|
|
|
(0.6
|
)
|
|
(22
|
)
|
|
—
|
|
—
|
|
|
|
|
|
(22
|
)
|
||||||||||
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
(1,230
|
)
|
|
|
|
(1,230
|
)
|
|||||||||||||
Balance, December 31, 2016
|
|
200.2
|
|
|
2
|
|
|
(1.2
|
)
|
|
(44
|
)
|
|
3,247
|
|
|
(2,265
|
)
|
|
(2
|
)
|
|
938
|
|
|||||||
Issuances of common stock
|
|
1.2
|
|
|
—
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
3
|
|
|||||||||||
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
53
|
|
|
|
|
|
|
53
|
|
|||||||||||||
Treasury stock, net
|
|
|
|
|
|
(0.5
|
)
|
|
(15
|
)
|
|
—
|
|
|
|
|
|
|
(15
|
)
|
|||||||||||
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
427
|
|
|
|
|
427
|
|
|||||||||||||
Other comprehensive income (loss), net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
2
|
|
|||||||||||||
Balance, December 31, 2017
|
|
201.4
|
|
|
$
|
2
|
|
|
(1.7
|
)
|
|
$
|
(59
|
)
|
|
$
|
3,303
|
|
|
$
|
(1,838
|
)
|
|
$
|
—
|
|
|
$
|
1,408
|
|
1
.
|
Organization and Summary of Significant Accounting Policies
|
•
|
the present value (
10%
per annum discount rate) of estimated future net revenues from proved reserves using oil, natural gas and NGL reserve estimation requirements, which require use of the unweighted average first-day-of-the-month commodity prices for the prior 12 months (SEC pricing), adjusted for market differentials applicable to our reserves (including the effects of derivative contracts that are designated for hedge accounting, if any); plus
|
•
|
the costs of properties not included in the costs being amortized, if any; less
|
•
|
related income tax effects.
|
|
|
2017
|
|
2016
|
||||
|
|
(In millions)
|
||||||
Revenue
|
|
$
|
175
|
|
|
$
|
163
|
|
Joint interest
|
|
108
|
|
|
53
|
|
||
Other
|
|
25
|
|
|
32
|
|
||
Reserve for doubtful accounts
|
|
(16
|
)
|
|
(16
|
)
|
||
Total accounts receivable, net
|
|
$
|
292
|
|
|
$
|
232
|
|
3
.
|
Inventories
|
4
.
|
Derivative Financial Instruments
|
•
|
Fixed-price swaps.
With respect to a swap position, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap strike price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap strike price.
|
•
|
Fixed-price swaps with sold puts.
A swap with a sold put position consists of a standard swap position plus a put sold by us with a strike price below the associated fixed-price swap. This structure enables us to increase the fixed-price swap with the value received through the sale of the put. If the settlement price for any settlement period falls equal to or below the put strike price, then we will only receive the difference between the swap price and the put strike price. If the settlement price is greater than the put strike price, the result is the same as it would have been with a standard swap only.
|
•
|
Swaptions.
A swaption is an option to exercise a swap where the buyer (counterparty) of the swaption purchases the right from the seller (Newfield), but not the obligation, to enter into a fixed-price swap with the seller on a predetermined date (expiration date). The swap price is a fixed price determined at the time of the swaption contract. If the swaption is exercised, the contract will become a swap treated consistent with our other fixed-price swaps.
|
•
|
Collars (combination of purchased put options (floor) and sold call options (ceiling))
. For a collar position, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor strike price while we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling strike price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor strike price and equal to or less than the ceiling strike price.
|
•
|
Collars with sold puts.
A collar with a sold put position consists of a standard collar position plus a put sold by us with a strike price below the floor strike price of the collar. This structure enables us to improve the collar strike prices with the value received through the sale of the additional put. If the settlement price for any settlement period falls equal to or below the additional put strike price, then we will receive the difference between the floor strike price and the additional put strike price. If the settlement price is greater than the additional put strike price, the result is the same as it would have been with a standard collar only.
|
|
|
|
|
NYMEX Contract Price Per Bbl
|
|
|
|||||||||||||||||
|
|
|
|
|
|
|
|
Collars
|
|
Estimated Fair Value
Asset (Liability) |
|||||||||||||
Period and Type of Instrument
|
|
Volume in MBbls
|
|
Swaps
(Weighted Average) |
|
Puts (Weighted Average)
|
|
Floors
(Weighted Average) |
|
Ceilings
(Weighted Average) |
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|||||||||||
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Swaptions
(1)
|
|
—
|
|
|
$
|
59.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
Fixed-price swaps
|
|
2,733
|
|
|
51.54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|||||
Fixed-price swaps with sold puts
|
|
644
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed-price swaps
|
|
|
|
56.78
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||
Sold puts
(2)
|
|
|
|
—
|
|
|
44.00
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Collars
|
|
2,002
|
|
|
|
|
|
|
50.59
|
|
|
56.70
|
|
|
(9
|
)
|
|||||||
Collars with sold puts:
|
|
14,315
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Collars
|
|
|
|
—
|
|
|
—
|
|
|
48.42
|
|
|
56.42
|
|
|
(62
|
)
|
||||||
Sold puts
|
|
|
|
—
|
|
|
39.46
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
||||||
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Collars with sold puts:
|
|
10,566
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Collars
|
|
|
|
—
|
|
|
—
|
|
|
50.59
|
|
|
57.13
|
|
|
(15
|
)
|
||||||
Sold puts
|
|
|
|
—
|
|
|
40.60
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
||||||
Total
|
|
$
|
(122
|
)
|
(1)
|
During the fourth quarter of 2017, we sold crude oil swaption contracts that, if exercised on their expiration date in the first quarter of 2018, would protect
273,000
Bbls of second quarter 2018 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at
$59.00
/bbl for second quarter 2018.
|
(2)
|
For the fixed-price swaps with sold puts, if the market price remains below our sold puts at contract settlement, we will receive the market price plus the difference between our swaps and our sold puts.
|
Period and Type of Instrument
|
|
|
|
NYMEX Contract Price Per MMBtu
|
|
|
||||||||||||||||||
|
|
|
|
|
|
Collars
|
|
|
||||||||||||||||
Volume in
MMMBtus
|
|
Swaps
(Weighted
Average)
|
|
Puts (Weighted Average)
|
|
Floors (Weighted
Average)
|
|
Ceilings (Weighted
Average)
|
|
Estimated
Fair Value
Asset
(Liability)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
||||||||||||
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed-price swaps
|
|
42,100
|
|
|
$
|
2.99
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
Collars
|
|
23,500
|
|
|
—
|
|
|
—
|
|
|
3.08
|
|
|
3.61
|
|
|
7
|
|
||||||
Collars with sold puts
|
|
6,420
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Collars
|
|
|
|
—
|
|
|
—
|
|
|
2.87
|
|
|
3.32
|
|
|
1
|
|
|||||||
Sold puts
|
|
|
|
—
|
|
|
2.30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed-price swaps
|
|
3,650
|
|
|
2.91
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Collars
|
|
9,000
|
|
|
—
|
|
|
|
|
3.00
|
|
|
3.47
|
|
|
1
|
|
|||||||
Total
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16
|
|
Period and Type of Instrument
|
|
|
|
Mont Belvieu Contract Price Per Gallon
|
|
|
||||||
Volume in MBbls
|
|
Swaps
(Weighted
Average)
|
|
Estimated Fair Value
Asset
(Liability)
|
||||||||
|
|
|
|
|
|
(In millions)
|
||||||
2018:
|
|
|
|
|
|
|
||||||
Fixed-price swaps
|
|
1,184
|
|
|
$
|
0.81
|
|
|
$
|
(2
|
)
|
|
Total
|
|
|
|
|
|
$
|
(2
|
)
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||||||||||||||||||
|
|
Gross Fair Value
|
|
Offset in Balance Sheet
|
|
Balance Sheet Location
|
|
Gross Fair Value
|
|
Offset in Balance Sheet
|
|
Balance Sheet Location
|
||||||||||||||||||||
|
|
|
|
Current
|
|
Noncurrent
|
|
|
|
Current
|
|
Noncurrent
|
||||||||||||||||||||
December 31, 2017
|
|
(In millions)
|
|
(In millions)
|
||||||||||||||||||||||||||||
Oil positions
|
|
$
|
48
|
|
|
$
|
(48
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(170
|
)
|
|
$
|
48
|
|
|
$
|
(96
|
)
|
|
$
|
(26
|
)
|
Natural gas positions
|
|
22
|
|
|
(6
|
)
|
|
15
|
|
|
1
|
|
|
(6
|
)
|
|
6
|
|
|
—
|
|
|
—
|
|
||||||||
NGL positions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
||||||||
Total
|
|
$
|
70
|
|
|
$
|
(54
|
)
|
|
$
|
15
|
|
|
$
|
1
|
|
|
$
|
(178
|
)
|
|
$
|
54
|
|
|
$
|
(98
|
)
|
|
$
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Oil positions
|
|
$
|
226
|
|
|
$
|
(151
|
)
|
|
$
|
75
|
|
|
$
|
—
|
|
|
$
|
(197
|
)
|
|
$
|
151
|
|
|
$
|
(46
|
)
|
|
$
|
—
|
|
Natural gas positions
|
|
10
|
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
(64
|
)
|
|
10
|
|
|
(51
|
)
|
|
(3
|
)
|
||||||||
NGL positions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total
|
|
$
|
236
|
|
|
$
|
(161
|
)
|
|
$
|
75
|
|
|
$
|
—
|
|
|
$
|
(261
|
)
|
|
$
|
161
|
|
|
$
|
(97
|
)
|
|
$
|
(3
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
||||||
Realized gain (loss) on oil positions
|
|
$
|
48
|
|
|
$
|
199
|
|
|
$
|
375
|
|
Realized gain (loss) on natural gas positions
|
|
(12
|
)
|
|
2
|
|
|
130
|
|
|||
Realized gain (loss) on NGL positions
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total realized gain (loss)
|
|
36
|
|
|
201
|
|
|
505
|
|
|||
Unrealized gain (loss) on oil positions
|
|
(152
|
)
|
|
(316
|
)
|
|
(165
|
)
|
|||
Unrealized gain (loss) on natural gas positions
|
|
71
|
|
|
(76
|
)
|
|
(81
|
)
|
|||
Unrealized gain (loss) on NGL positions
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|||
Total unrealized gain (loss)
|
|
(83
|
)
|
|
(392
|
)
|
|
(246
|
)
|
|||
Total
|
|
$
|
(47
|
)
|
|
$
|
(191
|
)
|
|
$
|
259
|
|
5
.
|
Fair Value Measurements
|
Level 1:
|
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
|
Level 2:
|
Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and, as of the third quarter of 2017, commodity options (i.e. price collars, sold puts, purchased calls or swaptions).
|
Level 3:
|
Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).
|
|
|
Fair Value Measurement Classification
|
|
|
||||||||||||
|
|
Quoted Prices
in Active
Markets for
Identical Assets
or (Liabilities)
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Total
|
||||||||
|
|
(In millions)
|
||||||||||||||
As of December 31, 2017:
|
|
|
|
|
|
|
|
|
||||||||
Money market fund investments
|
|
$
|
162
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
162
|
|
Deferred compensation plan assets
|
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
||||
Equity securities available-for-sale
|
|
12
|
|
|
—
|
|
|
—
|
|
|
12
|
|
||||
Oil, gas and NGL derivative contracts
|
|
—
|
|
|
(108
|
)
|
|
—
|
|
|
(108
|
)
|
||||
Stock-based compensation liability awards
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
||||
Total
|
|
$
|
174
|
|
|
$
|
(108
|
)
|
|
$
|
—
|
|
|
$
|
66
|
|
As of December 31, 2016:
|
|
|
|
|
|
|
|
|
||||||||
Money market fund investments
|
|
$
|
320
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
320
|
|
Deferred compensation plan assets
|
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
||||
Equity securities available-for-sale
|
|
9
|
|
|
—
|
|
|
—
|
|
|
9
|
|
||||
Oil and gas derivative swap contracts
|
|
—
|
|
|
50
|
|
|
—
|
|
|
50
|
|
||||
Oil and gas derivative option contracts
|
|
—
|
|
|
—
|
|
|
(75
|
)
|
|
(75
|
)
|
||||
Stock-based compensation liability awards
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
||||
Total
|
|
$
|
324
|
|
|
$
|
50
|
|
|
$
|
(75
|
)
|
|
$
|
299
|
|
|
|
Derivatives
|
|
Stock-Based Compensation
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
Balance at January 1, 2015
|
|
$
|
(381
|
)
|
|
$
|
(3
|
)
|
|
$
|
(384
|
)
|
Unrealized gains (losses) included in earnings
|
|
(217
|
)
|
|
3
|
|
|
(214
|
)
|
|||
Purchases, issuances, sales and settlements:
|
|
|
|
|
|
|
||||||
Settlements
|
|
290
|
|
|
—
|
|
|
290
|
|
|||
Transfers into Level 3
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Transfers out of Level 3
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Balance at December 31, 2015
|
|
$
|
(308
|
)
|
|
$
|
—
|
|
|
$
|
(308
|
)
|
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2015
|
|
$
|
(143
|
)
|
|
$
|
3
|
|
|
$
|
(140
|
)
|
Balance at January 1, 2016
|
|
$
|
(308
|
)
|
|
$
|
—
|
|
|
$
|
(308
|
)
|
Unrealized gains (losses) included in earnings
|
|
(33
|
)
|
|
—
|
|
|
(33
|
)
|
|||
Purchases, issuances, sales and settlements:
|
|
|
|
|
|
|
||||||
Settlements
|
|
220
|
|
|
—
|
|
|
220
|
|
|||
Transfers into Level 3
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Transfers out of Level 3
(1)
|
|
46
|
|
|
—
|
|
|
46
|
|
|||
Balance at December 31, 2016
|
|
$
|
(75
|
)
|
|
$
|
—
|
|
|
$
|
(75
|
)
|
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2016
|
|
$
|
13
|
|
|
$
|
—
|
|
|
$
|
13
|
|
Balance at January 1, 2017
|
|
$
|
(75
|
)
|
|
$
|
—
|
|
|
$
|
(75
|
)
|
Unrealized gains (losses) included in earnings
|
|
(17
|
)
|
|
—
|
|
|
(17
|
)
|
|||
Purchases, issuances, sales and settlements:
|
|
|
|
|
|
|
||||||
Settlements
|
|
30
|
|
|
—
|
|
|
30
|
|
|||
Transfers into Level 3
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Transfers out of Level 3
(2)
|
|
62
|
|
|
—
|
|
|
62
|
|
|||
Balance at December 31, 2017
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2017
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
During the second quarter of 2016, we transferred
$46 million
of derivative option contracts out of the Level 3 category as a result of our Level 3 swaptions being exercised by the counterparties as swaps in June 2016.
|
(2)
|
During the third quarter of 2017, we transferred
$62 million
of derivative option contracts out of the Level 3 hierarchy into Level 2 hierarchy as a result of our ability to derive volatility inputs from directly observable sources.
|
|
|
2017
|
|
2016
|
||||
|
|
(In millions)
|
||||||
5¾% Senior Notes due 2022
|
|
$
|
802
|
|
|
$
|
789
|
|
5⅝% Senior Notes due 2024
|
|
1,089
|
|
|
1,044
|
|
||
5⅜% Senior Notes due 2026
|
|
739
|
|
|
714
|
|
6
.
|
Oil and Gas Properties
|
|
|
2017
|
|
2016
|
||||
|
|
(In millions)
|
||||||
Proved
|
|
$
|
23,272
|
|
|
$
|
21,998
|
|
Unproved
|
|
1,200
|
|
|
1,238
|
|
||
Gross oil and gas properties
|
|
24,472
|
|
|
23,236
|
|
||
Accumulated depreciation, depletion and amortization
|
|
(10,032
|
)
|
|
(9,587
|
)
|
||
Accumulated impairment
|
|
(10,509
|
)
|
|
(10,509
|
)
|
||
Net oil and gas properties
|
|
$
|
3,931
|
|
|
$
|
3,140
|
|
|
|
Costs Incurred In
|
|
|
||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
Total
|
||||||||||
|
|
(In millions)
|
||||||||||||||||||
Acquisition costs
|
|
$
|
108
|
|
|
$
|
483
|
|
|
$
|
274
|
|
|
$
|
46
|
|
|
$
|
911
|
|
Exploration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Capitalized internal cost
|
|
38
|
|
|
49
|
|
|
32
|
|
|
15
|
|
|
134
|
|
|||||
Capitalized interest
|
|
61
|
|
|
51
|
|
|
33
|
|
|
10
|
|
|
155
|
|
|||||
Total costs withheld from amortization
|
|
$
|
207
|
|
|
$
|
583
|
|
|
$
|
339
|
|
|
$
|
71
|
|
|
$
|
1,200
|
|
(1)
|
Starting in the first quarter of 2016, there was no tax impact due to a full valuation allowance on our deferred tax assets. See Note
8
, "
Income Taxes
," for additional information regarding the deferred tax asset valuation allowance.
|
(2)
|
Excludes domestic rig impairment of
$4 million
.
|
7
.
|
Other Property and Equipment
|
|
|
2017
|
|
2016
|
||||
|
|
(In millions)
|
||||||
Furniture, fixtures and equipment
|
|
$
|
165
|
|
|
$
|
150
|
|
Gathering systems and equipment
|
|
115
|
|
|
115
|
|
||
Accumulated depreciation and amortization
|
|
(112
|
)
|
|
(98
|
)
|
||
Net other property and equipment
|
|
$
|
168
|
|
|
$
|
167
|
|
8
.
|
Income Taxes
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
U.S.
|
|
$
|
357
|
|
|
$
|
(1,181
|
)
|
|
$
|
(4,865
|
)
|
International
|
|
29
|
|
|
(27
|
)
|
|
(82
|
)
|
|||
Total income (loss) before income taxes
|
|
$
|
386
|
|
|
$
|
(1,208
|
)
|
|
$
|
(4,947
|
)
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
Current taxes:
|
|
|
|
|
|
|
||||||
U.S. federal
|
|
$
|
(79
|
)
|
|
$
|
(13
|
)
|
|
$
|
(12
|
)
|
U.S. state
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|||
International
|
|
1
|
|
|
22
|
|
|
31
|
|
|||
|
|
(78
|
)
|
|
9
|
|
|
17
|
|
|||
Deferred taxes:
|
|
|
|
|
|
|
||||||
U.S. federal
|
|
4
|
|
|
10
|
|
|
(1,507
|
)
|
|||
U.S. state
|
|
37
|
|
|
13
|
|
|
(27
|
)
|
|||
International
|
|
(4
|
)
|
|
(10
|
)
|
|
(68
|
)
|
|||
|
|
$
|
37
|
|
|
$
|
13
|
|
|
$
|
(1,602
|
)
|
Total provision (benefit) for income taxes
|
|
$
|
(41
|
)
|
|
$
|
22
|
|
|
$
|
(1,585
|
)
|
|
2017
(1)
|
|
2016
|
||||
Deferred tax asset:
|
|
|
|
||||
Net operating loss carryforwards
|
$
|
314
|
|
|
$
|
301
|
|
Alternative Minimum Tax credit
|
—
|
|
|
73
|
|
||
Stock-based compensation
|
11
|
|
|
15
|
|
||
Oil and gas properties
|
15
|
|
|
306
|
|
||
Commodity derivatives
|
19
|
|
|
9
|
|
||
Foreign tax credit
|
—
|
|
|
593
|
|
||
Other
|
3
|
|
|
13
|
|
||
Total deferred tax asset
|
362
|
|
|
1,310
|
|
||
Deferred tax asset valuation allowances
|
(362
|
)
|
|
(1,310
|
)
|
||
Net deferred tax asset
|
—
|
|
|
—
|
|
||
Deferred tax liability:
|
|
|
|
||||
Commodity derivatives
|
—
|
|
|
—
|
|
||
Oil and gas properties
|
(76
|
)
|
|
(39
|
)
|
||
Total deferred tax liability
|
(76
|
)
|
|
(39
|
)
|
||
Net deferred tax liability
|
$
|
(76
|
)
|
|
$
|
(39
|
)
|
(1)
|
The December 31, 2017 deferred tax asset (liability) has been adjusted for the lower federal statutory rate under the Tax Act.
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
Balance at the beginning of the year
|
|
$
|
(1,310
|
)
|
|
$
|
(790
|
)
|
|
$
|
(549
|
)
|
Charged to provision for income taxes:
|
|
|
|
|
|
|
||||||
U.S. state net operating loss carryforwards
|
|
7
|
|
|
(4
|
)
|
|
(1
|
)
|
|||
U.S. federal and state valuation allowance
|
|
343
|
|
|
(466
|
)
|
|
(202
|
)
|
|||
Foreign tax credit valuation allowance
|
|
593
|
|
|
(21
|
)
|
|
(25
|
)
|
|||
China valuation allowance
|
|
5
|
|
|
(29
|
)
|
|
(13
|
)
|
|||
Balance at the end of the year
|
|
$
|
(362
|
)
|
|
$
|
(1,310
|
)
|
|
$
|
(790
|
)
|
|
|
2017
|
|
2016
|
||||
|
|
(In millions)
|
||||||
Revenue payable
|
|
$
|
239
|
|
|
$
|
196
|
|
Accrued capital costs
|
|
173
|
|
|
92
|
|
||
Accrued lease operating expenses
|
|
22
|
|
|
37
|
|
||
Employee incentive expense
|
|
44
|
|
|
48
|
|
||
Accrued interest on debt
|
|
67
|
|
|
67
|
|
||
Taxes payable
|
|
11
|
|
|
15
|
|
||
Other
|
|
35
|
|
|
43
|
|
||
Total accrued liabilities
|
|
$
|
591
|
|
|
$
|
498
|
|
10
.
|
Asset Retirement Obligations
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
Balance at January 1
|
|
$
|
156
|
|
|
$
|
194
|
|
|
$
|
186
|
|
Accretion expense
|
|
9
|
|
|
10
|
|
|
10
|
|
|||
Additions
(1)
|
|
3
|
|
|
15
|
|
|
6
|
|
|||
Revisions
(2)
|
|
(25
|
)
|
|
(23
|
)
|
|
(2
|
)
|
|||
Settlements
(3)
|
|
(10
|
)
|
|
(40
|
)
|
|
(6
|
)
|
|||
Balance at December 31
|
|
133
|
|
|
156
|
|
|
194
|
|
|||
Less: Current portion of ARO at December 31
|
|
(3
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|||
Total long-term ARO at December 31
|
|
$
|
130
|
|
|
$
|
154
|
|
|
$
|
192
|
|
(1)
|
For the year ended
December 31, 2016
, additions include
$8 million
of abandonment obligations assumed through our Anadarko Basin acquisition.
|
(2)
|
Revisions are primarily due to changes in cost estimates and timing of expected abandonment.
|
(3)
|
For the year ended
December 31, 2017
, settlements include
$7 million
related to the sale of our interest in the Bohai Bay field in China. For the year ended
December 31, 2016
, settlements include
$35 million
related to the sale of our Texas assets. See Note
6
, "
Oil and Gas Properties
."
|
11
.
|
Debt
|
|
|
2017
|
|
2016
|
||||
|
|
(In millions)
|
||||||
Senior unsecured debt:
|
|
|
|
|
||||
5¾% Senior Notes due 2022
|
|
$
|
750
|
|
|
$
|
750
|
|
5⅝% Senior Notes due 2024
|
|
1,000
|
|
|
1,000
|
|
||
5⅜% Senior Notes due 2026
|
|
700
|
|
|
700
|
|
||
Total senior unsecured debt
|
|
2,450
|
|
|
2,450
|
|
||
Debt issuance costs
|
|
(16
|
)
|
|
(19
|
)
|
||
Total long-term debt
|
|
$
|
2,434
|
|
|
$
|
2,431
|
|
12
.
|
Commitments and Contingencies
|
|
|
Firm
Transportation
|
|
Operating
Leases
(Office Space)
|
|
Drilling-Related
|
|
Other
|
|
Total
|
||||||||||
|
|
(In millions)
|
||||||||||||||||||
Year Ending December 31,
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2018
|
|
$
|
79
|
|
|
$
|
25
|
|
|
$
|
25
|
|
|
$
|
18
|
|
|
$
|
147
|
|
2019
|
|
78
|
|
|
23
|
|
|
—
|
|
|
14
|
|
|
115
|
|
|||||
2020
|
|
31
|
|
|
21
|
|
|
—
|
|
|
7
|
|
|
59
|
|
|||||
2021
|
|
21
|
|
|
22
|
|
|
—
|
|
|
3
|
|
|
46
|
|
|||||
2022
|
|
21
|
|
|
4
|
|
|
—
|
|
|
2
|
|
|
27
|
|
|||||
Thereafter
|
|
106
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
123
|
|
|||||
Total minimum future payments
|
|
$
|
336
|
|
|
$
|
95
|
|
|
$
|
25
|
|
|
$
|
61
|
|
|
$
|
517
|
|
|
|
Oil
|
|
Year Ending December 31,
|
|
(MBbls)
|
|
2018
|
|
12,220
|
|
2019
|
|
11,315
|
|
2020
|
|
8,136
|
|
2021
|
|
5,840
|
|
2022
|
|
5,840
|
|
Thereafter
|
|
15,600
|
|
Total delivery commitments
|
|
58,951
|
|
13
.
|
Stockholders' Equity Activity
|
14
.
|
Earnings Per Share
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions, except per share data)
|
||||||||||
Net income (loss)
|
|
$
|
427
|
|
|
$
|
(1,230
|
)
|
|
$
|
(3,362
|
)
|
|
|
|
|
|
|
|
||||||
Weighted-average shares (denominator):
|
|
|
|
|
|
|
||||||
Weighted-average shares — basic
|
|
199
|
|
|
193
|
|
|
159
|
|
|||
Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Weighted-average shares — diluted
|
|
200
|
|
|
193
|
|
|
159
|
|
|||
Excluded due to anti-dilutive effect
|
|
1
|
|
|
2
|
|
|
3
|
|
|||
|
|
|
|
|
|
|
||||||
Earnings (loss) per share:
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
2.14
|
|
|
$
|
(6.36
|
)
|
|
$
|
(21.18
|
)
|
Diluted
|
|
$
|
2.13
|
|
|
$
|
(6.36
|
)
|
|
$
|
(21.18
|
)
|
15
.
|
Stock-Based Compensation
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
Equity awards
|
|
$
|
53
|
|
|
$
|
32
|
|
|
$
|
42
|
|
Liability awards
|
|
5
|
|
|
21
|
|
|
12
|
|
|||
Total stock-based compensation expense
|
|
58
|
|
|
53
|
|
|
54
|
|
|||
Capitalized in oil and gas properties
|
|
(17
|
)
|
|
(17
|
)
|
|
(18
|
)
|
|||
Net stock-based compensation expense
|
|
$
|
41
|
|
|
$
|
36
|
|
|
$
|
36
|
|
|
|
Service-Based
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
per Share
|
|
Market-Based
Shares
|
|
Weighted-
Average
Grant Date
Fair Value
per Share
|
|
Total
Shares
|
|||||||
|
|
(In thousands, except per share data)
|
|||||||||||||||
Non-vested shares outstanding at January 1, 2015
|
|
1,902
|
|
|
$
|
30.79
|
|
|
945
|
|
|
$
|
28.61
|
|
|
2,847
|
|
Granted
|
|
1,036
|
|
|
31.20
|
|
|
414
|
|
|
22.85
|
|
|
1,450
|
|
||
Forfeited
|
|
(367
|
)
|
|
21.69
|
|
|
(97
|
)
|
|
36.72
|
|
|
(464
|
)
|
||
Vested
|
|
(871
|
)
|
|
32.10
|
|
|
(188
|
)
|
|
39.42
|
|
|
(1,059
|
)
|
||
Non-vested shares outstanding at December 31, 2015
|
|
1,700
|
|
|
30.30
|
|
|
1,074
|
|
|
23.76
|
|
|
2,774
|
|
||
Granted
|
|
990
|
|
|
37.95
|
|
|
436
|
|
(1)
|
28.94
|
|
|
1,426
|
|
||
Forfeited
|
|
(217
|
)
|
|
29.15
|
|
|
(77
|
)
|
|
43.04
|
|
|
(294
|
)
|
||
Vested
|
|
(899
|
)
|
|
29.34
|
|
|
(574
|
)
|
|
21.36
|
|
|
(1,473
|
)
|
||
Non-vested shares outstanding at December 31, 2016
|
|
1,574
|
|
|
35.56
|
|
|
859
|
|
|
26.28
|
|
|
2,433
|
|
||
Granted
|
|
1,244
|
|
|
29.81
|
|
|
323
|
|
(2)
|
39.57
|
|
|
1,567
|
|
||
Forfeited
|
|
(91
|
)
|
|
34.43
|
|
|
(55
|
)
|
|
37.14
|
|
|
(146
|
)
|
||
Vested
|
|
(694
|
)
|
|
34.67
|
|
|
(386
|
)
|
|
29.43
|
|
|
(1,080
|
)
|
||
Non-vested shares outstanding at December 31, 2017
|
|
2,033
|
|
|
$
|
32.41
|
|
|
741
|
|
|
$
|
30.65
|
|
|
2,774
|
|
(1)
|
In February 2016, we granted approximately
436,000
restricted stock units, which based on achievement of certain criteria, could vest within a range of
0%
to
200%
of shares granted upon completion of the period ending December 31, 2018.
|
(2)
|
In February 2017, we granted approximately
323,000
restricted stock units, which based on achievement of certain criteria, could vest within a range of
0%
to
200%
of shares granted upon completion of the period ending December 31, 2019.
|
|
|
Number of Shares Underlying Options
|
|
Weighted-Average Exercise Price per Share
|
|
Weighted-Average Remaining Contractual Life
|
|
Aggregate
Intrinsic
Value
(1)
|
|||||
|
|
(In thousands)
|
|
|
|
(In years)
|
|
(In millions)
|
|||||
Outstanding and exercisable at:
|
|
|
|
|
|
|
|
|
|||||
December 31, 2015
|
|
195
|
|
|
$
|
48.45
|
|
|
2.1
|
|
$
|
—
|
|
December 31, 2016
|
|
177
|
|
|
48.45
|
|
|
1.1
|
|
—
|
|
||
December 31, 2017
|
|
155
|
|
|
48.45
|
|
|
0.1
|
|
—
|
|
|
|
Options Issued
|
|
Weighted-Average Fair Value per Share
|
|
Risk-free Interest Rate
|
|
Weighted-Average Volatility
|
|||||
|
|
(In thousands)
|
|
|
|
|
|
|
|||||
2015
|
|
136
|
|
|
$
|
8.71
|
|
|
0.12
|
%
|
|
49.41
|
%
|
2016
|
|
99
|
|
|
10.51
|
|
|
0.43
|
|
|
47.94
|
|
|
2017
|
|
124
|
|
|
9.03
|
|
|
0.87
|
|
|
39.13
|
|
|
|
Cash-Settled Restricted Stock Units
|
|
|
|
(In thousands)
|
|
Non-vested units outstanding at January 1, 2015
|
|
1,216
|
|
Granted
|
|
211
|
|
Forfeited
|
|
(257
|
)
|
Vested
|
|
(462
|
)
|
Non-vested units outstanding at December 31, 2015
|
|
708
|
|
Granted
|
|
299
|
|
Forfeited
|
|
(101
|
)
|
Vested
|
|
(446
|
)
|
Non-vested units outstanding at December 31, 2016
|
|
460
|
|
Granted
|
|
241
|
|
Forfeited
|
|
(32
|
)
|
Vested
|
|
(318
|
)
|
Non-vested units outstanding at December 31, 2017
|
|
351
|
|
16
.
|
Employee Benefit Plans
|
|
|
|
|
|
|
|
|
|
||||||
Type of Restructuring Cost
|
|
Location in the Consolidated Statement of Operations
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
|
|
(In millions)
|
||||||||||
Severance and related benefit costs
|
|
Operating expenses - General and administrative
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
7
|
|
Relocation costs
|
|
Operating expenses - General and administrative
|
|
2
|
|
|
5
|
|
|
5
|
|
|||
Office-lease abandonment costs
|
|
Operating expenses - General and administrative
|
|
—
|
|
|
6
|
|
|
14
|
|
|||
Other associated costs
|
|
Operating expenses - Depreciation, depletion and amortization
|
|
—
|
|
|
—
|
|
|
1
|
|
|||
Total
|
|
|
|
$
|
2
|
|
|
$
|
28
|
|
|
$
|
27
|
|
|
Severance and Related Benefit Costs
|
|
Office-lease Abandonment Costs
(1)
|
|
Relocation Costs
|
|
Other Associated Costs
|
|
Total
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Restructuring liability at January 1, 2015
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Additions
|
7
|
|
|
14
|
|
|
5
|
|
|
1
|
|
|
27
|
|
|||||
Settlements
|
(6
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|
(1
|
)
|
|
(13
|
)
|
|||||
Revisions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Restructuring liability at December 31, 2015
|
$
|
1
|
|
|
$
|
13
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14
|
|
Cumulative costs as of December 31, 2015
|
$
|
7
|
|
|
$
|
14
|
|
|
$
|
5
|
|
|
$
|
1
|
|
|
$
|
27
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Restructuring liability at January 1, 2016
|
$
|
1
|
|
|
$
|
13
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14
|
|
Additions
|
17
|
|
|
3
|
|
|
5
|
|
|
—
|
|
|
25
|
|
|||||
Settlements
|
(17
|
)
|
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|
(27
|
)
|
|||||
Revisions
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
Restructuring liability at December 31, 2016
|
$
|
1
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15
|
|
Cumulative costs as of December 31, 2016
|
$
|
24
|
|
|
$
|
20
|
|
|
$
|
10
|
|
|
$
|
1
|
|
|
$
|
55
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Restructuring liability at January 1, 2017
|
$
|
1
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15
|
|
Additions
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|||||
Settlements
|
(1
|
)
|
|
(6
|
)
|
|
(2
|
)
|
|
—
|
|
|
(9
|
)
|
|||||
Revisions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Restructuring liability at December 31, 2017
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8
|
|
Cumulative costs as of December 31, 2017
|
$
|
24
|
|
|
$
|
20
|
|
|
$
|
12
|
|
|
$
|
1
|
|
|
$
|
57
|
|
Expected total costs
|
$
|
24
|
|
|
$
|
20
|
|
|
$
|
12
|
|
|
$
|
1
|
|
|
$
|
57
|
|
(1)
|
The office-lease abandonment liability will be relieved as lease payments are made and sublease income is received over the life of the lease ending 2022.
|
18
.
|
Segment Information
|
|
|
Domestic
|
|
China
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
Year Ended December 31, 2017:
|
|
|
|
|
|
|
||||||
Oil, gas and NGL revenues
|
|
$
|
1,679
|
|
|
$
|
86
|
|
|
$
|
1,765
|
|
Lease operating
|
|
188
|
|
|
27
|
|
|
215
|
|
|||
Transportation and processing
|
|
300
|
|
|
—
|
|
|
300
|
|
|||
Production and other taxes
|
|
64
|
|
|
—
|
|
|
64
|
|
|||
Depreciation, depletion and amortization
|
|
443
|
|
|
24
|
|
|
467
|
|
|||
Results of operations for oil and gas producing activities before tax
|
|
684
|
|
|
35
|
|
|
719
|
|
|||
Other revenues
|
|
2
|
|
|
—
|
|
|
2
|
|
|||
General and administrative
|
|
194
|
|
|
6
|
|
|
200
|
|
|||
Other
|
|
5
|
|
|
1
|
|
|
6
|
|
|||
Allocated income tax (benefit)
(1)
|
|
180
|
|
|
17
|
|
|
|
|
|||
Net income (loss) from oil and gas properties
|
|
$
|
307
|
|
|
$
|
11
|
|
|
|
||
|
|
|
|
|
|
|
||||||
Total revenues
|
|
|
|
|
|
1,767
|
|
|||||
Total operating expenses
|
|
|
|
|
|
1,252
|
|
|||||
Income (loss) from operations
|
|
|
|
|
|
515
|
|
|||||
Interest expense, net of interest income, capitalized interest and other
|
|
|
|
|
|
(82
|
)
|
|||||
Commodity derivative income (expense)
|
|
|
|
|
|
(47
|
)
|
|||||
Income (loss) from operations before income taxes
|
|
|
|
|
|
$
|
386
|
|
||||
Total assets
|
|
$
|
4,875
|
|
|
$
|
86
|
|
|
$
|
4,961
|
|
Additions to long-lived assets
|
|
$
|
1,288
|
|
|
$
|
1
|
|
|
$
|
1,289
|
|
(1)
|
Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of
37%
for domestic and
60%
for China.
|
|
|
Domestic
|
|
China
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
Year Ended December 31, 2016:
|
|
|
|
|
|
|
||||||
Oil, gas and NGL revenues
|
|
$
|
1,251
|
|
|
$
|
217
|
|
|
$
|
1,468
|
|
Lease operating
|
|
189
|
|
|
55
|
|
|
244
|
|
|||
Transportation and processing
|
|
272
|
|
|
—
|
|
|
272
|
|
|||
Production and other taxes
|
|
41
|
|
|
1
|
|
|
42
|
|
|||
Depreciation, depletion and amortization
|
|
458
|
|
|
114
|
|
|
572
|
|
|||
Ceiling test and other impairments
|
|
962
|
|
|
66
|
|
|
1,028
|
|
|||
Results of operations for oil and gas producing activities before tax
|
|
(671
|
)
|
|
(19
|
)
|
|
(690
|
)
|
|||
Other revenues
|
|
4
|
|
|
—
|
|
|
4
|
|
|||
General and administrative
|
|
205
|
|
|
8
|
|
|
213
|
|
|||
Other
|
|
20
|
|
|
—
|
|
|
20
|
|
|||
Allocated income tax (benefit)
(1)
|
|
(330
|
)
|
|
(16
|
)
|
|
|
||||
Net income (loss) from oil and gas properties
|
|
$
|
(562
|
)
|
|
$
|
(11
|
)
|
|
|
||
|
|
|
|
|
|
|
||||||
Total revenues
|
|
|
|
|
|
1,472
|
|
|||||
Total operating expenses
|
|
|
|
|
|
2,391
|
|
|||||
Income (loss) from operations
|
|
|
|
|
|
(919
|
)
|
|||||
Interest expense, net of interest income, capitalized interest and other
|
|
|
|
|
|
(98
|
)
|
|||||
Commodity derivative income (expense)
|
|
|
|
|
|
(191
|
)
|
|||||
Income (loss) from operations before income taxes
|
|
|
|
|
|
$
|
(1,208
|
)
|
||||
Total assets
|
|
$
|
4,166
|
|
|
$
|
146
|
|
|
$
|
4,312
|
|
Additions to long-lived assets
|
|
$
|
1,369
|
|
|
$
|
2
|
|
|
$
|
1,371
|
|
(1)
|
Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of
37%
for domestic and
60%
for China.
|
|
|
Domestic
|
|
China
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
Year Ended December 31, 2015:
|
|
|
|
|
|
|
||||||
Oil, gas and NGL revenues
|
|
$
|
1,288
|
|
|
$
|
262
|
|
|
$
|
1,550
|
|
Lease operating
|
|
231
|
|
|
54
|
|
|
285
|
|
|||
Transportation and processing
|
|
212
|
|
|
—
|
|
|
212
|
|
|||
Production and other taxes
|
|
45
|
|
|
1
|
|
|
46
|
|
|||
Depreciation, depletion and amortization
|
|
754
|
|
|
163
|
|
|
917
|
|
|||
Ceiling test and other impairments
|
|
4,786
|
|
|
118
|
|
|
4,904
|
|
|||
Results of operations for oil and gas producing activities before tax
|
|
(4,740
|
)
|
|
(74
|
)
|
|
(4,814
|
)
|
|||
Other revenues
|
|
7
|
|
|
—
|
|
|
7
|
|
|||
General and administrative
|
|
237
|
|
|
7
|
|
|
244
|
|
|||
Other
|
|
9
|
|
|
1
|
|
|
10
|
|
|||
Allocated income tax (benefit)
(1)
|
|
(1,842
|
)
|
|
(49
|
)
|
|
|
||||
Net income (loss) from oil and gas properties
|
|
$
|
(3,137
|
)
|
|
$
|
(33
|
)
|
|
|
||
|
|
|
|
|
|
|
||||||
Total revenues
|
|
|
|
|
|
1,557
|
|
|||||
Total operating expenses
|
|
|
|
|
|
6,618
|
|
|||||
Income (loss) from operations
|
|
|
|
|
|
(5,061
|
)
|
|||||
Interest expense, net of interest income, capitalized interest and other
|
|
|
|
|
|
(145
|
)
|
|||||
Commodity derivative income (expense)
|
|
|
|
|
|
259
|
|
|||||
Income (loss) from operations before income taxes
|
|
|
|
|
|
$
|
(4,947
|
)
|
||||
Total assets
|
|
$
|
4,452
|
|
|
$
|
316
|
|
|
$
|
4,768
|
|
Additions to long-lived assets
|
|
$
|
1,645
|
|
|
$
|
100
|
|
|
$
|
1,745
|
|
(1)
|
Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of
37%
% for domestic and
60%
for China.
|
19.
|
Supplemental Cash Flow Information
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In millions)
|
||||||||||
Cash Payments:
|
|
|
|
|
|
|
||||||
Interest payments
|
|
$
|
84
|
|
|
$
|
97
|
|
|
$
|
119
|
|
Income tax payments (refunds)
|
|
(2
|
)
|
|
17
|
|
|
25
|
|
|||
Non-cash investing and financing activities excluded from the statement of cash flows:
|
|
|
|
|
|
|
||||||
(Increase) decrease in receivables for property sales
|
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
6
|
|
(Increase) decrease in accrued capital expenditures
|
|
(81
|
)
|
|
33
|
|
|
225
|
|
|||
(Increase) decrease in asset retirement costs
|
|
31
|
|
|
46
|
|
|
(4
|
)
|
20.
|
Quarterly Results of Operations (Unaudited)
|
|
|
2017 Quarter Ended
|
||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
|
(In millions, except per share data)
|
||||||||||||||
Oil, gas and NGL revenues
|
|
$
|
417
|
|
|
$
|
402
|
|
|
$
|
439
|
|
|
$
|
509
|
|
Income (loss) from operations
|
|
121
|
|
|
99
|
|
|
112
|
|
|
183
|
|
||||
Net income (loss)
|
|
147
|
|
|
98
|
|
|
87
|
|
|
95
|
|
||||
Basic earnings (loss) per share
(1)
|
|
0.74
|
|
|
0.49
|
|
|
0.44
|
|
|
0.47
|
|
||||
Diluted earnings (loss) per share
(1)
|
|
0.73
|
|
|
0.49
|
|
|
0.44
|
|
|
0.47
|
|
|
|
2016 Quarter Ended
|
||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
|
(In millions, except per share data)
|
||||||||||||||
Oil, gas and NGL revenues
|
|
$
|
284
|
|
|
$
|
381
|
|
|
$
|
392
|
|
|
$
|
415
|
|
Ceiling test and other impairments
|
|
506
|
|
|
522
|
|
|
—
|
|
|
—
|
|
||||
Income (loss) from operations
(2)
|
|
(578
|
)
|
|
(498
|
)
|
|
45
|
|
|
112
|
|
||||
Net income (loss)
(2)
|
|
(624
|
)
|
|
(667
|
)
|
|
48
|
|
|
13
|
|
||||
Basic earnings (loss) per share
(1)
|
|
(3.52
|
)
|
|
(3.36
|
)
|
|
0.24
|
|
|
0.07
|
|
||||
Diluted earnings (loss) per share
(1)
|
|
(3.52
|
)
|
|
(3.36
|
)
|
|
0.24
|
|
|
0.07
|
|
(1)
|
The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted-average number of shares outstanding during that quarter.
|
(2)
|
Income (loss) from operations and Net income (loss) for the third quarter of 2016 include a legal settlement of $
18 million
. See Note
12
, "
Commitments and Contingencies
—
Litigation
" for additional information.
|
|
|
Domestic
|
|
China
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
2017:
|
|
|
|
|
|
|
||||||
Property acquisitions:
|
|
|
|
|
|
|
||||||
Unproved
|
|
$
|
98
|
|
|
$
|
—
|
|
|
$
|
98
|
|
Proved
|
|
104
|
|
|
—
|
|
|
104
|
|
|||
Exploration
|
|
704
|
|
|
—
|
|
|
704
|
|
|||
Development
|
|
430
|
|
|
5
|
|
|
435
|
|
|||
Total costs incurred
(1)
|
|
$
|
1,336
|
|
|
$
|
5
|
|
|
$
|
1,341
|
|
|
|
|
|
|
|
|
||||||
2016:
|
|
|
|
|
|
|
||||||
Property acquisitions:
|
|
|
|
|
|
|
||||||
Unproved
|
|
$
|
491
|
|
|
$
|
—
|
|
|
$
|
491
|
|
Proved
|
|
88
|
|
|
—
|
|
|
88
|
|
|||
Exploration
|
|
535
|
|
|
—
|
|
|
535
|
|
|||
Development
|
|
210
|
|
|
(1
|
)
|
|
209
|
|
|||
Total costs incurred
(1)
|
|
$
|
1,324
|
|
|
$
|
(1
|
)
|
|
$
|
1,323
|
|
|
|
|
|
|
|
|
||||||
2015:
|
|
|
|
|
|
|
||||||
Property acquisitions:
|
|
|
|
|
|
|
||||||
Unproved
|
|
$
|
283
|
|
|
$
|
1
|
|
|
$
|
284
|
|
Proved
|
|
21
|
|
|
—
|
|
|
21
|
|
|||
Exploration
|
|
578
|
|
|
—
|
|
|
578
|
|
|||
Development
|
|
630
|
|
|
15
|
|
|
645
|
|
|||
Total costs incurred
(1)
|
|
$
|
1,512
|
|
|
$
|
16
|
|
|
$
|
1,528
|
|
(1)
|
Includes net changes in asset retirement costs of
$(20) million
,
$(8) million
and
$4 million
for
2017
,
2016
and
2015
, respectively.
|
|
|
Domestic
|
|
China
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
December 31, 2017:
|
|
|
|
|
|
|
||||||
Proved properties
|
|
$
|
22,638
|
|
|
$
|
634
|
|
|
$
|
23,272
|
|
Unproved properties
|
|
1,200
|
|
|
—
|
|
|
1,200
|
|
|||
|
|
23,838
|
|
|
634
|
|
|
24,472
|
|
|||
Accumulated depreciation, depletion and amortization
|
|
(9,614
|
)
|
|
(418
|
)
|
|
(10,032
|
)
|
|||
Accumulated impairment
|
|
(10,325
|
)
|
|
(184
|
)
|
|
(10,509
|
)
|
|||
Net capitalized costs
|
|
$
|
3,899
|
|
|
$
|
32
|
|
|
$
|
3,931
|
|
|
|
|
|
|
|
|
||||||
December 31, 2016:
|
|
|
|
|
|
|
||||||
Proved properties
|
|
$
|
21,331
|
|
|
$
|
667
|
|
|
$
|
21,998
|
|
Unproved properties
|
|
1,238
|
|
|
—
|
|
|
1,238
|
|
|||
|
|
22,569
|
|
|
667
|
|
|
23,236
|
|
|||
Accumulated depreciation, depletion and amortization
|
|
(9,192
|
)
|
|
(395
|
)
|
|
(9,587
|
)
|
|||
Accumulated impairment
|
|
(10,325
|
)
|
|
(184
|
)
|
|
(10,509
|
)
|
|||
Net capitalized costs
|
|
$
|
3,052
|
|
|
$
|
88
|
|
|
$
|
3,140
|
|
|
|
2017
|
|
2016
|
||||
|
|
(In millions)
|
||||||
Property sales — Domestic
|
|
$
|
65
|
|
|
$
|
398
|
|
Property sales — Domestic asset retirement costs
|
|
3
|
|
|
37
|
|
||
Property sales — China
|
|
31
|
|
|
—
|
|
||
Property sales — China asset retirement costs
|
|
7
|
|
|
—
|
|
||
Ceiling test impairment — Domestic
|
|
—
|
|
|
962
|
|
||
Ceiling test impairment — China
|
|
—
|
|
|
66
|
|
||
|
|
$
|
106
|
|
|
$
|
1,463
|
|
|
|
Year Ended December 31,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
|
|
(MMBOE)
|
|||||||
Proved Reserves:
|
|
|
|
|
|
|
|||
Beginning of year
|
|
513
|
|
|
509
|
|
|
645
|
|
Reserve additions
|
|
76
|
|
|
77
|
|
|
102
|
|
Reserve revisions
|
|
153
|
|
|
21
|
|
|
(174
|
)
|
Sales of properties
|
|
(4
|
)
|
|
(35
|
)
|
|
(8
|
)
|
Production
|
|
(58
|
)
|
|
(59
|
)
|
|
(56
|
)
|
End of year
|
|
680
|
|
|
513
|
|
|
509
|
|
|
|
Crude Oil
and Condensate (MMBbls)
|
|
Natural Gas (Bcf)
|
||||||||||||||
|
|
Domestic
|
|
China
(1)
|
|
Total
|
|
Domestic
|
|
China
(1)
|
|
Total
|
||||||
Proved developed and undeveloped reserves as of:
|
|
|
|
|
|
|
|
|||||||||||
December 31, 2014
|
|
278
|
|
|
23
|
|
|
301
|
|
|
1,607
|
|
|
—
|
|
|
1,607
|
|
Revisions of previous estimates
|
|
(105
|
)
|
|
(7
|
)
|
|
(112
|
)
|
|
(352
|
)
|
|
—
|
|
|
(352
|
)
|
Extensions, discoveries and other additions
|
|
49
|
|
|
—
|
|
|
49
|
|
|
187
|
|
|
—
|
|
|
187
|
|
Purchases of properties
|
|
1
|
|
|
—
|
|
|
1
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Sales of properties
|
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|
(15
|
)
|
|
—
|
|
|
(15
|
)
|
Production
|
|
(21
|
)
|
|
(6
|
)
|
|
(27
|
)
|
|
(124
|
)
|
|
—
|
|
|
(124
|
)
|
December 31, 2015
|
|
197
|
|
|
10
|
|
|
207
|
|
|
1,305
|
|
|
—
|
|
|
1,305
|
|
Revisions of previous estimates
|
|
(9
|
)
|
|
—
|
|
|
(9
|
)
|
|
116
|
|
|
—
|
|
|
116
|
|
Extensions, discoveries and other additions
|
|
19
|
|
|
—
|
|
|
19
|
|
|
92
|
|
|
—
|
|
|
92
|
|
Purchases of properties
|
|
12
|
|
|
—
|
|
|
12
|
|
|
90
|
|
|
—
|
|
|
90
|
|
Sales of properties
|
|
(13
|
)
|
|
—
|
|
|
(13
|
)
|
|
(102
|
)
|
|
—
|
|
|
(102
|
)
|
Production
|
|
(21
|
)
|
|
(5
|
)
|
|
(26
|
)
|
|
(135
|
)
|
|
—
|
|
|
(135
|
)
|
December 31, 2016
|
|
185
|
|
|
5
|
|
|
190
|
|
|
1,366
|
|
|
—
|
|
|
1,366
|
|
Revisions of previous estimates
|
|
50
|
|
|
2
|
|
|
52
|
|
|
318
|
|
|
—
|
|
|
318
|
|
Extensions, discoveries and other additions
|
|
35
|
|
|
—
|
|
|
35
|
|
|
151
|
|
|
—
|
|
|
151
|
|
Purchases of properties
|
|
1
|
|
|
—
|
|
|
1
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Sales of properties
|
|
(1
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
Production
|
|
(22
|
)
|
|
(2
|
)
|
|
(24
|
)
|
|
(130
|
)
|
|
—
|
|
|
(130
|
)
|
December 31, 2017
|
|
248
|
|
|
2
|
|
|
250
|
|
|
1,704
|
|
|
—
|
|
|
1,704
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2014
|
|
135
|
|
|
9
|
|
|
144
|
|
|
938
|
|
|
—
|
|
|
938
|
|
December 31, 2015
|
|
115
|
|
|
10
|
|
|
125
|
|
|
942
|
|
|
—
|
|
|
942
|
|
December 31, 2016
|
|
104
|
|
|
5
|
|
|
109
|
|
|
928
|
|
|
—
|
|
|
928
|
|
December 31, 2017
|
|
136
|
|
|
2
|
|
|
138
|
|
|
1,099
|
|
|
—
|
|
|
1,099
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2014
|
|
143
|
|
|
14
|
|
|
157
|
|
|
669
|
|
|
—
|
|
|
669
|
|
December 31, 2015
|
|
82
|
|
|
—
|
|
|
82
|
|
|
363
|
|
|
—
|
|
|
363
|
|
December 31, 2016
|
|
81
|
|
|
—
|
|
|
81
|
|
|
438
|
|
|
—
|
|
|
438
|
|
December 31, 2017
|
|
112
|
|
|
—
|
|
|
112
|
|
|
605
|
|
|
—
|
|
|
605
|
|
(1)
|
All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method.
|
|
|
NGLs (MMBbls)
|
|
Total (MMBOE)
|
||||||||||||||
|
|
Domestic
|
|
China
(1)
|
|
Total
|
|
Domestic
|
|
China
(1)
|
|
Total
|
||||||
Proved developed and undeveloped reserves as of:
|
|
|
|
|
|
|
|
|||||||||||
December 31, 2014
|
|
76
|
|
|
—
|
|
|
76
|
|
|
622
|
|
|
23
|
|
|
645
|
|
Revisions of previous estimates
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
(167
|
)
|
|
(7
|
)
|
|
(174
|
)
|
Extensions, discoveries and other additions
|
|
20
|
|
|
—
|
|
|
20
|
|
|
101
|
|
|
—
|
|
|
101
|
|
Purchases of properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Sales of properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
Production
|
|
(9
|
)
|
|
—
|
|
|
(9
|
)
|
|
(50
|
)
|
|
(6
|
)
|
|
(56
|
)
|
December 31, 2015
|
|
84
|
|
|
—
|
|
|
84
|
|
|
499
|
|
|
10
|
|
|
509
|
|
Revisions of previous estimates
|
|
13
|
|
|
—
|
|
|
13
|
|
|
21
|
|
|
—
|
|
|
21
|
|
Extensions, discoveries and other additions
|
|
8
|
|
|
—
|
|
|
8
|
|
|
42
|
|
|
—
|
|
|
42
|
|
Purchases of properties
|
|
7
|
|
|
—
|
|
|
7
|
|
|
35
|
|
|
—
|
|
|
35
|
|
Sales of properties
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
|
(35
|
)
|
|
—
|
|
|
(35
|
)
|
Production
|
|
(11
|
)
|
|
—
|
|
|
(11
|
)
|
|
(54
|
)
|
|
(5
|
)
|
|
(59
|
)
|
December 31, 2016
|
|
95
|
|
|
—
|
|
|
95
|
|
|
508
|
|
|
5
|
|
|
513
|
|
Revisions of previous estimates
|
|
49
|
|
|
—
|
|
|
49
|
|
|
151
|
|
|
2
|
|
|
153
|
|
Extensions, discoveries and other additions
|
|
14
|
|
|
—
|
|
|
14
|
|
|
74
|
|
|
—
|
|
|
74
|
|
Purchases of properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Sales of properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(3
|
)
|
|
(4
|
)
|
Production
|
|
(12
|
)
|
|
—
|
|
|
(12
|
)
|
|
(56
|
)
|
|
(2
|
)
|
|
(58
|
)
|
December 31, 2017
|
|
146
|
|
|
—
|
|
|
146
|
|
|
678
|
|
|
2
|
|
|
680
|
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|||||||||||
December 31, 2014
|
|
38
|
|
|
—
|
|
|
38
|
|
|
329
|
|
|
9
|
|
|
338
|
|
December 31, 2015
|
|
47
|
|
|
—
|
|
|
47
|
|
|
319
|
|
|
10
|
|
|
329
|
|
December 31, 2016
|
|
50
|
|
|
—
|
|
|
50
|
|
|
309
|
|
|
5
|
|
|
314
|
|
December 31, 2017
|
|
78
|
|
|
—
|
|
|
78
|
|
|
398
|
|
|
2
|
|
|
400
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
|||||||||||
December 31, 2014
|
|
38
|
|
|
—
|
|
|
38
|
|
|
293
|
|
|
14
|
|
|
307
|
|
December 31, 2015
|
|
37
|
|
|
—
|
|
|
37
|
|
|
180
|
|
|
—
|
|
|
180
|
|
December 31, 2016
|
|
45
|
|
|
—
|
|
|
45
|
|
|
199
|
|
|
—
|
|
|
199
|
|
December 31, 2017
|
|
68
|
|
|
—
|
|
|
68
|
|
|
280
|
|
|
—
|
|
|
280
|
|
(1)
|
All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method.
|
|
|
Domestic
|
|
China
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
December 31, 2017:
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
$
|
20,346
|
|
|
$
|
120
|
|
|
$
|
20,466
|
|
Less related future:
|
|
|
|
|
|
|
||||||
Production costs
|
|
(8,193
|
)
|
|
(53
|
)
|
|
(8,246
|
)
|
|||
Development and abandonment costs
|
|
(2,786
|
)
|
|
(16
|
)
|
|
(2,802
|
)
|
|||
Future net cash flows before income taxes
|
|
9,367
|
|
|
51
|
|
|
9,418
|
|
|||
Future income tax expense
|
|
(1,091
|
)
|
|
—
|
|
|
(1,091
|
)
|
|||
Future net cash flows before 10% discount
|
|
8,276
|
|
|
51
|
|
|
8,327
|
|
|||
10% annual discount for estimating timing of cash flows
|
|
(3,922
|
)
|
|
(4
|
)
|
|
(3,926
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
4,354
|
|
|
$
|
47
|
|
|
$
|
4,401
|
|
|
|
|
|
|
|
|
||||||
December 31, 2016:
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
$
|
11,778
|
|
|
$
|
220
|
|
|
$
|
11,998
|
|
Less related future:
|
|
|
|
|
|
|
||||||
Production costs
|
|
(5,191
|
)
|
|
(96
|
)
|
|
(5,287
|
)
|
|||
Development and abandonment costs
|
|
(1,993
|
)
|
|
(44
|
)
|
|
(2,037
|
)
|
|||
Future net cash flows before income taxes
|
|
4,594
|
|
|
80
|
|
|
4,674
|
|
|||
Future income tax expense
|
|
(207
|
)
|
|
—
|
|
|
(207
|
)
|
|||
Future net cash flows before 10% discount
|
|
4,387
|
|
|
80
|
|
|
4,467
|
|
|||
10% annual discount for estimating timing of cash flows
|
|
(1,867
|
)
|
|
(16
|
)
|
|
(1,883
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
2,520
|
|
|
$
|
64
|
|
|
$
|
2,584
|
|
|
|
|
|
|
|
|
||||||
December 31, 2015:
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
$
|
12,932
|
|
|
$
|
512
|
|
|
$
|
13,444
|
|
Less related future:
|
|
|
|
|
|
|
||||||
Production costs
|
|
(5,914
|
)
|
|
(202
|
)
|
|
(6,116
|
)
|
|||
Development and abandonment costs
|
|
(2,262
|
)
|
|
(44
|
)
|
|
(2,306
|
)
|
|||
Future net cash flows before income taxes
|
|
4,756
|
|
|
266
|
|
|
5,022
|
|
|||
Future income tax expense
|
|
(211
|
)
|
|
3
|
|
|
(208
|
)
|
|||
Future net cash flows before 10% discount
|
|
4,545
|
|
|
269
|
|
|
4,814
|
|
|||
10% annual discount for estimating timing of cash flows
|
|
(1,991
|
)
|
|
(47
|
)
|
|
(2,038
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
2,554
|
|
|
$
|
222
|
|
|
$
|
2,776
|
|
|
|
Domestic
|
|
China
|
|
Total
|
||||||
|
|
(In millions)
|
||||||||||
2017:
|
|
|
|
|
|
|
||||||
Beginning of the period
|
|
$
|
2,520
|
|
|
$
|
64
|
|
|
$
|
2,584
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
||||||
Changes in prices and costs
|
|
1,393
|
|
|
(9
|
)
|
|
1,384
|
|
|||
Changes in quantities
|
|
1,387
|
|
|
42
|
|
|
1,429
|
|
|||
Changes in future development costs
|
|
(728
|
)
|
|
13
|
|
|
(715
|
)
|
|||
Previously estimated development costs incurred during the period
|
|
456
|
|
|
1
|
|
|
457
|
|
|||
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs
|
|
658
|
|
|
—
|
|
|
658
|
|
|||
Purchases and sales of reserves in place, net
|
|
21
|
|
|
(46
|
)
|
|
(25
|
)
|
|||
Accretion of discount
|
|
247
|
|
|
6
|
|
|
253
|
|
|||
Sales of oil and gas, net of production costs
|
|
(1,127
|
)
|
|
(59
|
)
|
|
(1,186
|
)
|
|||
Net change in income taxes
|
|
(444
|
)
|
|
—
|
|
|
(444
|
)
|
|||
Production timing and other
|
|
(29
|
)
|
|
35
|
|
|
6
|
|
|||
Net increase (decrease)
|
|
1,834
|
|
|
(17
|
)
|
|
1,817
|
|
|||
End of period
|
|
$
|
4,354
|
|
|
$
|
47
|
|
|
$
|
4,401
|
|
2016:
|
|
|
|
|
|
|
||||||
Beginning of the period
|
|
$
|
2,554
|
|
|
$
|
222
|
|
|
$
|
2,776
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
||||||
Changes in prices and costs
|
|
(481
|
)
|
|
(27
|
)
|
|
(508
|
)
|
|||
Changes in quantities
|
|
153
|
|
|
4
|
|
|
157
|
|
|||
Changes in future development costs
|
|
186
|
|
|
2
|
|
|
188
|
|
|||
Previously estimated development costs incurred during the period
|
|
228
|
|
|
—
|
|
|
228
|
|
|||
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs
|
|
418
|
|
|
—
|
|
|
418
|
|
|||
Purchases and sales of reserves in place, net
|
|
135
|
|
|
—
|
|
|
135
|
|
|||
Accretion of discount
|
|
235
|
|
|
16
|
|
|
251
|
|
|||
Sales of oil and gas, net of production costs
|
|
(749
|
)
|
|
(161
|
)
|
|
(910
|
)
|
|||
Net change in income taxes
|
|
63
|
|
|
—
|
|
|
63
|
|
|||
Production timing and other
|
|
(222
|
)
|
|
8
|
|
|
(214
|
)
|
|||
Net increase (decrease)
|
|
(34
|
)
|
|
(158
|
)
|
|
(192
|
)
|
|||
End of period
|
|
$
|
2,520
|
|
|
$
|
64
|
|
|
$
|
2,584
|
|
2015:
|
|
|
|
|
|
|
||||||
Beginning of the period
|
|
$
|
5,330
|
|
|
$
|
882
|
|
|
$
|
6,212
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
||||||
Changes in prices and costs
|
|
(6,126
|
)
|
|
(528
|
)
|
|
(6,654
|
)
|
|||
Changes in quantities
|
|
(1,140
|
)
|
|
(181
|
)
|
|
(1,321
|
)
|
|||
Changes in future development costs
|
|
2,179
|
|
|
14
|
|
|
2,193
|
|
|||
Previously estimated development costs incurred during the period
|
|
630
|
|
|
16
|
|
|
646
|
|
|||
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs
|
|
522
|
|
|
4
|
|
|
526
|
|
|||
Purchases and sales of reserves in place, net
|
|
(21
|
)
|
|
—
|
|
|
(21
|
)
|
|||
Accretion of discount
|
|
855
|
|
|
88
|
|
|
943
|
|
|||
Sales of oil and gas, net of production costs
|
|
(800
|
)
|
|
(207
|
)
|
|
(1,007
|
)
|
|||
Net change in income taxes
|
|
2,229
|
|
|
182
|
|
|
2,411
|
|
|||
Production timing and other
|
|
(1,104
|
)
|
|
(48
|
)
|
|
(1,152
|
)
|
|||
Net increase (decrease)
|
|
(2,776
|
)
|
|
(660
|
)
|
|
(3,436
|
)
|
|||
End of period
|
|
$
|
2,554
|
|
|
$
|
222
|
|
|
$
|
2,776
|
|
Exhibit
Number
|
|
Title
|
3.1
|
—
|
|
|
|
|
3.2
|
—
|
|
|
|
|
4.1
|
—
|
|
|
|
|
4.1.1
|
—
|
|
|
|
|
4.1.2
|
—
|
|
|
|
|
4.1.3
|
—
|
|
|
|
|
4.2
|
—
|
|
|
|
|
†10.1
|
—
|
|
|
|
|
†10.1.1
|
—
|
|
|
|
|
†10.1.2
|
—
|
|
|
|
|
†10.1.3
|
—
|
|
|
|
|
†10.1.4
|
—
|
|
|
|
|
†10.1.5
|
—
|
|
|
|
|
†10.1.6
|
—
|
|
|
|
†10.1.7
|
—
|
|
|
|
|
†10.1.8
|
—
|
|
|
|
|
†10.1.9
|
—
|
|
|
|
|
†10.1.10
|
—
|
|
|
|
|
†10.1.11
|
—
|
|
|
|
|
†10.1.12
|
—
|
|
|
|
|
†10.1.13
|
—
|
|
|
|
|
†10.1.14
|
—
|
|
|
|
|
†10.1.15
|
—
|
|
|
|
|
†10.1.16
|
—
|
|
|
|
|
†10.1.17
|
—
|
|
|
|
|
†10.1.18
|
—
|
|
|
|
|
†10.2
|
—
|
|
|
|
|
†10.2.1
|
—
|
|
|
|
|
†10.2.2
|
—
|
|
|
|
|
†10.2.3
|
—
|
|
|
|
|
†10.3
|
—
|
|
|
|
|
†10.3.1
|
—
|
|
|
|
|
†10.4
|
—
|
|
|
|
|
†10.5
|
—
|
|
|
|
|
†10.5.1
|
—
|
|
|
|
|
†10.5.2
|
—
|
|
|
|
|
†10.6
|
—
|
|
|
|
|
†10.7
|
—
|
|
|
|
|
†10.8
|
—
|
|
|
|
|
†10.9
|
—
|
|
|
|
|
†10.10
|
—
|
|
|
|
|
†10.11
|
—
|
|
|
|
|
†10.12
|
—
|
|
|
|
|
10.13
|
—
|
|
|
|
|
10.13.1
|
—
|
|
|
|
|
10.13.2
|
—
|
|
|
|
|
10.13.3
|
—
|
|
|
|
|
10.13.4
|
—
|
|
|
|
|
10.13.5
|
—
|
|
|
|
|
10.14
|
—
|
|
|
|
|
*21.1
|
—
|
|
|
|
|
*23.1
|
—
|
|
|
|
|
*23.2
|
—
|
|
|
|
|
*23.3
|
—
|
|
|
|
|
*24.1
|
—
|
|
|
|
|
*31.1
|
—
|
|
|
|
|
*31.2
|
—
|
|
|
|
|
*32.1
|
—
|
|
|
|
|
*32.2
|
—
|
|
|
|
|
*99.1
|
—
|
|
|
|
*99.2
|
—
|
|
|
|
|
*101.INS
|
—
|
XBRL Instance Document
|
|
|
|
*101.SCH
|
—
|
XBRL Schema Document
|
|
|
|
*101.CAL
|
—
|
XBRL Calculation Linkbase Document
|
|
|
|
*101.LAB
|
—
|
XBRL Label Linkbase Document
|
|
|
|
*101.PRE
|
—
|
XBRL Presentation Linkbase Document
|
|
|
|
*101.DEF
|
—
|
XBRL Definition Linkbase Document
|
*
|
Filed or furnished herewith.
|
†
|
Identifies management contracts and compensatory plans or arrangements.
|
NEWFIELD EXPLORATION COMPANY
|
||
|
|
|
By:
|
|
/s/ LEE K. BOOTHBY
|
|
|
Lee K. Boothby
President and Chief Executive Officer
|
Signature
|
|
Title
|
|
|
|
|
|
/
S
/ LEE K. BOOTHBY
|
|
President, Chief Executive Officer and Chairman of the Board
|
|
Lee K. Boothby
|
|
(Principal Executive Officer)
|
|
|
|
|
|
/
S
/ LAWRENCE S. MASSARO
|
|
Executive Vice President and Chief Financial Officer
|
|
Lawrence S. Massaro
|
|
(Principal Financial Officer)
|
|
|
|
|
|
/
S
/ GEORGE W. FAIRCHILD, JR.
|
|
Chief Accounting Officer
|
|
George W. Fairchild, Jr.
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
/
S
/ PAMELA J. GARDNER*
|
|
Director
|
|
Pamela J. Gardner
|
|
|
|
|
|
|
|
/
S
/ STEVEN W. NANCE*
|
|
Director
|
|
Steven W. Nance
|
|
|
|
|
|
|
|
/
S
/ ROGER B. PLANK*
|
|
Director
|
|
Roger B. Plank
|
|
|
|
|
|
|
|
/
S
/ THOMAS G. RICKS*
|
|
Director
|
|
Thomas G. Ricks
|
|
|
|
|
|
|
|
/
S
/ JUANITA M. ROMANS*
|
|
Director
|
|
Juanita M. Romans
|
|
|
|
|
|
|
|
/
S
/ JOHN W. SCHANCK*
|
|
Director
|
|
|
John W. Schanck
|
|
|
|
|
|
|
/
S
/ J. TERRY STRANGE*
|
|
Director
|
|
J. Terry Strange
|
|
|
|
|
|
|
|
/
S
/ J. KENT WELLS*
|
|
Director
|
|
J. Kent Wells
|
|
|
|
|
|
|
|
/
S
/ EDGAR R. GIESINGER*
|
|
Director
|
|
Edgar R. Giesinger
|
|
|
|
|
|
|
|
*By:
|
/s/ GEORGE W. FAIRCHILD, JR.
|
|
|
|
George W. Fairchild, Jr.
as Attorney-in-Fact
|
|
|
Exhibit
Number
|
|
Title
|
3.1
|
—
|
Fourth Amended and Restated Certificate of Incorporation of Newfield Exploration Company dated July 20, 2015 (incorporated by reference to Exhibit 3.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 27, 2015 (File No. 1-12534))
|
|
|
|
3.2
|
—
|
Amended and Restated Bylaws of Newfield Exploration Company, as amended by the First Amendment dated November 11, 2016 (incorporated by reference to Exhibit 3.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-12534))
|
|
|
|
4.1
|
—
|
Senior Indenture dated as of February 28, 2001 between Newfield and First Union National Bank, as Trustee (the "Senior Indenture") (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 28, 2001 (File No. 1-12534))
|
|
|
|
4.1.1
|
—
|
Second Supplemental Indenture, dated as of September 30, 2011, to Senior Indenture between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed with the SEC on September 30, 2011 (File No. 1-12534))
|
|
|
|
4.1.2
|
—
|
Third Supplemental Indenture, dated as of June 26, 2012, to Senior Indenture between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed with the SEC on June 26, 2012 (File No. 1-12534))
|
|
|
|
4.1.3
|
—
|
Fourth Supplemental Indenture, dated as of March 10, 2015, to Senior Indenture between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield's Current Report on Form 8-K filed with the SEC on March 12, 2015 (File No. 1-12534))
|
|
|
|
4.2
|
—
|
Subordinated Indenture dated as of December 10, 2001 between Newfield and First Union National Bank, as Trustee (the "Subordinated Indenture") (incorporated by reference to Exhibit 4.5 to Newfield’s Registration Statement on Form S-3/A filed with the SEC on December 13, 2001 (File No. 333-71348))
|
|
|
|
†10.1
|
—
|
Newfield Exploration Company 2011 Omnibus Stock Plan (the "2011 Omnibus Stock Plan") (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8 filed with the SEC on May 5, 2011 (File No. 333-173964))
|
|
|
|
†10.1.1
|
—
|
Newfield Exploration Company 2011 Omnibus Stock Plan (As Amended and Restated May 2, 2013)(incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on May 3, 2013 (File No. 1-12534))
|
|
|
|
†10.1.2
|
—
|
Newfield Exploration Company 2011 Omnibus Stock Plan (As Amended and Restated May 15, 2015) (incorporated by reference to Exhibit 99.1 to Newfield’s Registration Statement on Form S-8 filed with the SEC on June 3, 2015 (File No. 333-204694))
|
|
|
|
†10.1.3
|
—
|
First Amendment to the Newfield Exploration Company 2011 Omnibus Stock Plan (As Amended and Restated May 15, 2015), effective April 12, 2016 (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016 (File No. 1-12534))
|
|
|
|
†10.1.4
|
—
|
Form of 2015 Executive Officer TSR Restricted Stock Unit Award Agreement under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.3 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015 (File No. 1-12534))
|
|
|
|
†10.1.5
|
—
|
Form of 2015 Cash-Settled Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.20 to Newfield's Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 1-12534))
|
|
|
|
†10.1.6
|
—
|
Form of 2015 Notice of Restricted Stock Unit Award and Attached Terms and Conditions under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.21 to Newfield's Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 1-12534))
|
|
|
|
†10.1.7
|
—
|
Form of 2016 Executive Officer Notice of Restricted Stock Unit Award Total Stockholder Return (TSR) and Attached Terms and Conditions under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016 (File No. 1-12534))
|
|
|
|
†10.1.8
|
—
|
Form of 2016 Cash-Settled Restricted Stock Unit Award Agreement and Attached Terms and Conditions (incorporated by reference to Exhibit 10.3 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016 (File No. 1-12534))
|
|
|
|
†10.1.9
|
—
|
Form of 2016 Notice of Restricted Stock Unit Award and Attached Terms and Conditions under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016 (File No. 1-12534))
|
|
|
|
†10.1.10
|
—
|
Form of 2016 Restricted Stock Agreement for Non-Employee Directors under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016 (File No. 1-12534))
|
|
|
|
†10.1.11
|
—
|
Form of 2016 Restricted Stock Unit Award Agreement for Non-Employee Directors under the 2011 Omnibus Stock Plan and the Newfield Exploration Company Non-Employee Directors' Deferred Compensation Plan (incorporated by reference to Exhibit 10.3 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016 (File No. 1-12534))
|
|
|
|
†10.1.12
|
—
|
Form of Tax Election Regarding Restricted Stock Unit Awards under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016 (File No. 1-12534))
|
|
|
|
†10.1.13
|
—
|
Form of 2017 Notice of Restricted Stock Unit Award Total Stockholder Return (TSR) and Attached Terms and Conditions under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017 (File No. 1-12534))
|
|
|
|
†10.1.14
|
—
|
Form of 2017 Cash-Settled Restricted Stock Unit Award Agreement and Attached Terms and Conditions (incorporated by reference to Exhibit 10.2 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017 (File No. 1-12534))
|
|
|
|
†10.1.15
|
—
|
Form of 2017 Notice of Restricted Stock Unit Award and Attached Terms and Conditions (Officer Form) under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.3 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017 (File No. 1-12534))
|
|
|
|
†10.1.16
|
—
|
Amendment to Total Stockholder Return (TSR) Notice of Restricted Stock Unit Award and Attached Terms and Conditions under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.4 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017 (File No. 1-12534))
|
|
|
|
†10.1.17
|
—
|
Form of 2017 Notice of Restricted Stock Unit Award and Attached Terms and Conditions (for Supplemental Awards) under the 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.5 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017 (File No. 1-12534))
|
|
|
|
†10.1.18
|
—
|
Form of 2017 Cash-Settled Restricted Stock Unit Award Agreement and Attached Terms and Conditions (for Supplemental Awards) (incorporated by reference to Exhibit 10.6 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017 (File No. 1-12534))
|
|
|
|
†10.2
|
—
|
Newfield Exploration Company 2017 Omnibus Incentive Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8, filed with the SEC on May 16, 2017 (File No. 333-218027)
|
|
|
|
†10.2.1
|
—
|
Form of 2017 Restricted Stock Agreement for Non-Employee Directors under the 2017 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.3 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017 (File No. 1-12534))
|
|
|
|
†10.2.2
|
—
|
Form of 2017 Restricted Stock Unit Award Agreement for Non-Employee Directors under the 2017 Omnibus Incentive Plan and the Non-Employee Directors' Deferred Compensation Plan (incorporated by reference to Exhibit 10.4 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017 (File No. 1-12534))
|
|
|
|
†10.2.3
|
—
|
Form of 2017 Notice of Restricted Stock Unit Award and Attached Terms and Conditions (New Hire and Promotions) under the 2017 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.5 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017 (File No. 1-12534))
|
|
|
|
†10.3
|
—
|
Newfield Exploration Company 2011 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.25 to Newfield's Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
|
|
|
|
†10.3.1
|
—
|
Newfield Exploration Company Amended and Restated 2011 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.4 to Newfield's Quarterly Report on Form 10-Q, for the quarterly period ended March 31, 2016 (File No. 1-12534))
|
|
|
|
†10.4
|
—
|
Newfield Exploration Company Deferred Compensation Plan (As Amended and Restated effective May 15, 2015) (incorporated by reference to Exhibit 10.5 to Newfield's Annual Report on Form 10-K, for the year ended December 31, 2015 (File No. 1-12534))
|
|
|
|
†10.5
|
—
|
Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8 filed with the SEC on May 10, 2010 (File No. 333-166672))
|
|
|
|
†10.5.1
|
—
|
Amendment No. 1 to the Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on February 11, 2014 (File No. 1-12534))
|
|
|
|
†10.5.2
|
—
|
Newfield Exploration Company Amended and Restated 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8, filed with the SEC on May 16, 2017 (File No. 333-218026)
|
|
|
|
†10.6
|
—
|
Newfield Exploration Company Non-Employee Directors' Deferred Compensation Plan (Effective as of October 27, 2015) (incorporated by reference to Exhibit 10.24 to Newfield's Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 1-12534))
|
|
|
|
†10.7
|
—
|
Fourth Amended and Restated Newfield Exploration Company Change of Control Severance Plan (incorporated by reference to Exhibit 10.18 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2012 (File No. 1-12534))
|
|
|
|
†10.8
|
—
|
Form of Third Amended and Restated Change of Control Severance Agreement between Newfield and Lee K. Boothby dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.31 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
|
|
|
|
†10.9
|
—
|
Form of Second Amended and Restated Change of Control Severance Agreement between Newfield and each of John H. Jasek and James T. Zernell dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.32 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
|
|
|
|
†10.10
|
—
|
Form of Fourth Amended and Restated Change of Control Severance Agreement between Newfield and each of George T. Dunn and Gary D. Packer dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.33 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
|
|
|
|
†10.11
|
—
|
Amended and Restated Change of Control Severance Agreement, by and between the Company and Lawrence S. Massaro, effective as of February 10, 2016 (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on February 12, 2016 (File No. 1-12534))
|
|
|
|
†10.12
|
—
|
Form of Indemnification Agreement between Newfield and each of its directors and executive officers (incorporated by reference to Exhibit 10.20 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))
|
|
|
|
10.13
|
—
|
Credit Agreement, dated as of June 2, 2011, by and among Newfield, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and DNB Nor Bank ASA, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (File No. 1-12534))
|
|
|
|
10.13.1
|
—
|
First Amendment to Credit Agreement, dated as of September 27, 2011, by and among Newfield, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (File No. 1-12534))
|
|
|
|
10.13.2
|
—
|
Second Amendment to Credit Agreement, dated as of April 29, 2013, by and among Newfield, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.36.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 1-12534))
|
|
|
|
10.13.3
|
—
|
Third Amendment to Credit Agreement, dated as of June 25, 2013, by and among Newfield, as Borrower, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., DNB Bank ASA, Sumitomo Mitsui Banking Corporation and U.S. Bank National Association, as Documentation Agents (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013 (File No. 1-12534))
|
|
|
|
10.13.4
|
—
|
Fourth Amendment to Credit Agreement, dated as of March 5, 2015, by and among Newfield, as Borrower, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd., The Bank of Nova Scotia, U.S. Bank National Association, Sumitomo Mitsui Banking Corporation and Credit Suisse AG, Cayman Islands Branch, as Documentation Agents, and BMO Harris Bank N.A., Canadian Imperial Bank of Commerce, New York Branch, Goldman Sachs Bank USA and Mizuho Bank Ltd., as Managing Agents (incorporated by reference to Exhibit 10.2 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015 (File No. 1-12534))
|
|
|
|
10.13.5
|
—
|
Fifth Amendment to Credit Agreement, dated as of March 18, 2016, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.5 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016 (File No. 1-12534))
|
|
|
|
10.14
|
—
|
Retirement Agreement of William D. Schneider (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on January 14, 2015 (File No. 1-12534))
|
|
|
|
*21.1
|
—
|
List of Significant Subsidiaries
|
|
|
|
*23.1
|
—
|
Consent of PricewaterhouseCoopers LLP
|
|
|
|
*23.2
|
—
|
Consent of Ryder Scott Company, L.P.
|
|
|
|
*23.3
|
—
|
Consent of DeGolyer and MacNaughton
|
|
|
|
*24.1
|
—
|
Power of Attorney
|
|
|
|
*31.1
|
—
|
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
*31.2
|
—
|
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
*32.1
|
—
|
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
*32.2
|
—
|
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
*99.1
|
—
|
Reserve Audit Report of Ryder Scott Company, L.P., dated January 12, 2018
|
|
|
|
*99.2
|
—
|
Reserve Audit Report of DeGolyer and MacNaughton, dated January 16, 2018
|
|
|
|
*101.INS
|
—
|
XBRL Instance Document
|
|
|
|
*101.SCH
|
—
|
XBRL Schema Document
|
|
|
|
*101.CAL
|
—
|
XBRL Calculation Linkbase Document
|
|
|
|
*101.LAB
|
—
|
XBRL Label Linkbase Document
|
|
|
|
*101.PRE
|
—
|
XBRL Presentation Linkbase Document
|
|
|
|
*101.DEF
|
—
|
XBRL Definition Linkbase Document
|
*
|
Filed or furnished herewith.
|
†
|
Identifies management contracts and compensatory plans or arrangements.
|
Exact Name of Subsidiary and Name
Under Which Subsidiary Does Business
|
|
Jurisdiction of
Incorporation or Organization
|
Newfield Exploration Mid-Continent Inc.
|
|
Delaware
|
Newfield Rocky Mountains Inc.
|
|
Delaware
|
Newfield Production Company
|
|
Texas
|
/s/Ryder Scott Company, L.P.
|
Ryder Scott Company, L.P.
|
TBPE Firm Registration No. F-1580
|
February 20, 2018
|
Exhibit 23.3
|
Very truly yours,
|
|
|
|
/s/DeGolyer and MacNaughton
|
DeGolyer and MacNAUGHTON
|
Texas Registered Engineering Firm F-716
|
|
|
Signature
|
Title
|
|
|
/s/ Lee K. Boothby
|
President, Chief Executive Officer and Chairman of the Board
|
Lee K. Boothby
|
|
|
|
/s/ Lawrence S. Massaro
|
Executive Vice President and Chief Financial Officer
|
Lawrence S. Massaro
|
|
|
|
/s/ George W. Fairchild, Jr.
|
Chief Accounting Officer
|
George W. Fairchild, Jr.
|
|
|
|
/s/ Pamela J. Gardner
|
Director
|
Pamela J. Gardner
|
|
|
|
/s/ Edgar R. Giesinger
|
Director
|
Edgar R. Giesinger
|
|
|
|
/s/ Steven W. Nance
|
Director
|
Steven W. Nance
|
|
|
|
/s/ Roger B. Plank
|
Director
|
Roger B. Plank
|
|
|
|
/s/ Thomas G. Ricks
|
Director
|
Thomas G. Ricks
|
|
|
|
/s/ Juanita M. Romans
|
Director
|
Juanita M. Romans
|
|
|
|
/s/ John W. Schanck
|
Director
|
John W. Schanck
|
|
|
|
/s/ J. Terry Strange
|
Director
|
J. Terry Strange
|
|
|
|
/s/ J. Kent Wells
|
Director
|
J. Kent Wells
|
|
1.
|
I have reviewed this annual report on Form 10-K for the annual period ended
December 31, 2017
of Newfield Exploration Company (the “Registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
|
4.
|
The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:
|
a.
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and
|
5.
|
The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s Board of Directors (or persons performing the equivalent functions):
|
a.
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.
|
Date: February 20, 2018
|
By:
|
/s/ LEE K. BOOTHBY
|
|
|
Lee K. Boothby
|
|
|
President and Chief Executive Officer
|
|
|
(Principal Executive Officer)
|
1.
|
I have reviewed this annual report on Form 10-K for the annual period ended
December 31, 2017
of Newfield Exploration Company (the “Registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
|
4.
|
The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:
|
a.
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and
|
5.
|
The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s Board of Directors (or persons performing the equivalent functions):
|
a.
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.
|
Date: February 20, 2018
|
By:
|
/s/ LAWRENCE S. MASSARO
|
|
|
Lawrence S. Massaro
|
|
|
Executive Vice President and Chief Financial Officer
|
|
|
(Principal Financial Officer)
|
Date: February 20, 2018
|
|
/s/ LEE K. BOOTHBY
|
|
|
Lee K. Boothby
|
|
|
(Principal Executive Officer)
|
Date: February 20, 2018
|
|
/s/ LAWRENCE S. MASSARO
|
|
|
Lawrence S. Massaro
|
|
|
(Principal Financial Officer)
|
/s/ Stephen E. Gardner
|
Stephen E. Gardner, P.E.
|
Colorado License No. 44720
|
Senior Vice President [Seal]
|
SEC PARAMETERS
|
||||||||
Estimated Net Reserves
|
||||||||
Certain Leasehold and Royalty Interests of
|
||||||||
Newfield Exploration Company
|
||||||||
As of December 31, 2017
|
||||||||
|
|
|
||||||
|
|
Proved
|
||||||
|
|
Developed
|
|
|
|
Total
|
||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate – MBBLS
|
|
74,714
|
|
2,210
|
|
27,736
|
|
104,660
|
Plant Products – MBBLS
|
|
9,945
|
|
0
|
|
2,914
|
|
12,859
|
Gas – MMCF
|
|
100,586
|
|
0
|
|
41,028
|
|
141,614
|
|
|
|
|
|
|
|
|
|
Not Audited by Ryder Scott
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate – MBBLS
|
|
60,077
|
|
1,344
|
|
84,043
|
|
145,464
|
Plant Products – MBBLS
|
|
67,225
|
|
1171
|
|
65,169
|
|
133,565
|
Gas – MMCF
|
|
978,100
|
|
20,015
|
|
563,858
|
|
1,561,973
|
|
|
|
|
|
|
|
|
|
Total Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate – MBBLS
|
|
134,791
|
|
3,554
|
|
111,779
|
|
250,124
|
Plant Products – MBBLS
|
|
77,170
|
|
1171
|
|
68,083
|
|
146,424
|
Gas – MMCF
|
|
1,078,686
|
|
20,015
|
|
604,886
|
|
1,703,587
|
Geographic Area
|
Product
|
Price
Reference
|
Average
Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
United States
|
Oil/Condensate
|
WTI Cushing
|
$51.34/Bbl
|
$43.50/Bbl
|
NGLs
|
WTI Cushing
|
$51.34/Bbl
|
$27.95/Bbl
|
|
Gas
|
Henry Hub
|
$2.98/MMBTU
|
$1.52/MCF
|
|
|
|
|
|
|
Asia
|
|
|
|
|
South China Sea
|
Oil
|
WTI Cushing
|
$51.34/Bbl
|
$54.32/Bbl
|
Very truly yours,
|
|
RYDER SCOTT COMPANY, L.P.
|
TBPE Firm Registration No. F-1580
|
|
|
|
/s/ Stephen E. Gardner
|
Stephen E. Gardner, P.E.
|
Colorado License No. 44720
|
Senior Vice President
|
[Seal]
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
January 16, 2018
|
Exhibit 99.2
|
DeGolyer and MacNaughton
|
|
2
|
DeGolyer and MacNaughton
|
|
3
|
DeGolyer and MacNaughton
|
|
4
|
DeGolyer and MacNaughton
|
|
5
|
DeGolyer and MacNaughton
|
|
6
|
DeGolyer and MacNaughton
|
|
7
|
Submitted,
|
|
/s/DeGOLYER and MacNAUGHTON
|
|
DeGOLYER and MacNAUGHTON
|
Texas Registered Engineering Firm F-716
|
/s/Gregory K. Graves, P.E.
|
|
Gregory K. Graves, P.E.
|
Senior Vice President
|
DeGolyer and MacNaughton
|
DeGolyer and MacNaughton
|
|
8
|
1.
|
That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Newfield dated January 16, 2018, and that I, as Senior Vice President, was responsible for the preparation of this letter report.
|
2.
|
That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 33 years of experience in oil and gas reservoir studies and reserves evaluations.
|
/s/Gregory K. Graves, P.E.
|
|
Gregory K. Graves, P.E.
|
Senior Vice President
|
DeGolyer and MacNaughton
|