NFX 2014 10-K v2

 
 
 
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K 
 
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended December 31, 2014
or
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from              to              .
Commission file number: 1-12534
Newfield Exploration Company
(Exact name of registrant as specified in its charter)
Delaware
 
72-1133047
(State of incorporation)
 
(I.R.S. Employer Identification No.)
4 Waterway Square Place,
Suite 100,
The Woodlands, Texas
 
77380
(Zip Code)
(Address of principal executive offices)
 
 
Registrant’s telephone number, including area code:
(281) 210-5100
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share
 
New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ¨    No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  þ
 
Accelerated filer ¨ 
 
Non-accelerated filer  ¨
 
Smaller reporting company  ¨
       (Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $5.9 billion as of June 30, 2014 (based on the last sale price of such stock as quoted on the New York Stock Exchange).
As of February 20, 2015, there were 137,387,180 shares of the registrant’s common stock, par value $0.01 per share, outstanding.
Documents incorporated by reference: Portions of the Proxy Statement of Newfield Exploration Company for the Annual Meeting of Stockholders to be held May 15, 2015, which is incorporated by reference to the extent specified in Part III of this Form 10-K.
 
 
 
 
 


TABLE OF CONTENTS
 
 
Page
 
PART I
Items 1 and 2.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 3.
Item 4.
 
PART II
Item 5.
 
 
 
 
Item 6.
Item 7.
 
 
 
 
 
 
 
 
 
 
 
Item 7A.

i

 
 
Page
 
 
 
Item 8.
Item 9.
Item 9A.
 
 
 
Item 9B.
 
PART III
Item 10.
 
Item 11.
Item 12.
Item 13.
Item 14.
 
PART IV
Item 15.
 
 
 
 
 
 


ii

If you are not familiar with any of the oil and gas terms used in this report, we have provided explanations of many of them under the caption “Commonly Used Oil and Gas Terms” at the end of Items 1 and 2 of this report. Unless the context otherwise requires, all references in this report to “Newfield,” “we,” “us,” “our” or the “Company” are to Newfield Exploration Company and its subsidiaries. Unless otherwise noted, all information in this report relating to oil and gas reserves and the estimated future net cash flows attributable to those reserves are based on estimates we prepared and are net to our interest.

Forward-Looking Information

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). All statements, other than statements of historical facts included in this report, are forward-looking, including information relating to anticipated future events or results, such as planned capital expenditures, the availability and sources of capital resources to fund capital expenditures and other plans and objectives for future operations. Forward-looking statements are typically identified by use of terms such as “may,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “potential” and similar expressions that convey the uncertainty of future events or outcomes. Although we believe that the expectations reflected in such forward-looking statements are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including:

•oil, natural gas and natural gas liquids (NGL) prices;
•
the availability and volatility of the securities, capital or credit markets and the cost of capital to fund our operations and business strategies;
•
accuracy and fluctuations in our reserves estimates due to sustained low commodity prices;
•
ability to develop existing reserves or acquire new reserves;
•the timing and our success in discovering, producing and estimating reserves;
•sustained decline in commodity prices could result in writedowns of assets;
•operating hazards inherent in the exploration for and production of oil and natural gas;
•general economic, financial, industry or business trends or conditions;
•
the impact of, and changes in, legislation, law and governmental regulations, including those related to hydraulic fracturing, climate change and over-the-counter derivatives;
•
land, legal, regulatory, and ownership complexities inherent in the U.S. oil and gas industry;
•
the impact of regulatory approvals;
•
the availability and volatility of the securities, capital or credit markets and the cost of capital to fund our operations and business strategies;
•
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;
•
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;
•the volatility and liquidity in the commodity futures and commodity and financial derivatives markets;
•drilling risks and results;
•the prices and availability of goods and services;
•the cost and availability of drilling rigs and other support services;
•global events that may impact our domestic and international operating contracts, markets and prices;

1

•labor conditions;
•weather conditions;
•environmental liabilities that are not covered by an effective indemnity or insurance;
•competitive conditions;
•terrorism or civil or political unrest in a region or country;
•our ability to monetize non-strategic assets, pay debt and the impact of changes in our investment ratings;
•electronic, cyber or physical security breaches;
•changes in tax rates;
•inflation rates;
•financial counterparty risk;
•the effect of worldwide energy conservation measures;
•the price and availability of, and demand for, competing energy sources;
•the availability (or lack thereof) of acquisition, disposition or combination opportunities; and
•the other factors affecting our business described below under the caption “Risk Factors.”

Should one or more of the risks described above occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements in this report, as well as all other written and oral forward-looking statements attributable to us or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in this section and elsewhere in this report. See Items 1 and 2, “Business and Properties,” Item 1A, “Risk Factors,” Item 3, “Legal Proceedings,” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” for additional information about factors that may affect our businesses and operating results. These factors are not necessarily all of the important factors that could affect us. Use caution and common sense when considering these forward-looking statements. Unless securities laws require us to do so, we do not undertake any obligation to publicly correct or update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.


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PART I
Items 1 and 2.
Business and Properties

General

Newfield Exploration Company is an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. We are a Delaware corporation, incorporated in 1988, that has been publicly traded on the New York Stock Exchange (NYSE) since 1993. We have a unique history of growth, evolving from an offshore, Gulf of Mexico natural gas producer to an onshore, domestic producer focused on liquids-rich resource plays and included in the S&P 500.

Our principal areas of operation are oil and liquids-rich resource plays in the Mid-Continent, Rocky Mountains and onshore Gulf Coast regions of the United States. In addition, we have offshore oil developments in China.

Executive Summary

•
Domestic production increased 19% over 2013 to 47.9(1) MMBOE. Domestic liquids production grew 38% year-over-year. Consolidated fourth quarter production was 138(2) MBOEPD (60% liquids);

•
Thirteen year reserve life index (based on 2014 production);

•
Approximately 96% of Newfield's 645 MMBOE of proved reserves (47% oil, 12% NGLs and 41% natural gas) are located onshore U.S. Domestic liquids reserves increased 17% year-over-year and represent 57% of domestic proved reserves;

•
Proved reserves grew 14% year-over-year (adjusted for 2014 asset sales of 49 MMBOE). Total company and domestic PV-10(3) increased 9% and 16%, respectively, over the prior year-end to $8.8 billion and $7.7 billion, respectively. Approximately 52% of reserves are proved developed;

•
The Anadarko Basin is now the Company's largest producing region, averaging 54,000 BOEPD in the fourth quarter of 2014. The Anadarko Basin comprises 28% of total proved reserves. Acreage in the basin increased to nearly 300,000 net acres;

•
Demonstrated continued operational efficiencies, drilling "best in class" wells in each of our four primary focus areas. Average domestic lease operating expenses, on a per barrel basis, decreased 7% over 2013;

•
Sold $1.5 billion in non-strategic assets and used proceeds to redeem our $600 million 7⅛% Senior Subordinated Notes due 2018; and

•
Commenced production from the Pearl oil development, located offshore China.
_________________
(1) Includes 8.5 Bcf of natural gas produced and consumed in operations.

(2) Includes 2.1 Bcf (3.8 MBOEPD) of natural gas produced and consumed in operations.

(3) PV-10 (as defined) is considered a non-GAAP financial measure by the SEC. See non-GAAP reconciliation in "Reserves – Reserves Sensitivities" below.



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2015 Outlook

Until the last six months, crude oil prices have been reasonably stable, with NYMEX WTI averaging approximately $95 per barrel over the past four years. During this time period, relatively easy access to low-cost capital and advances in horizontal drilling and fracture stimulations led to significant growth in U.S. oil supply. Production in the U.S. in October 2014 surpassed 9 million barrels a day, a level not seen since the mid-1980s. As a result of increased U.S. production as well as other global supply and demand factors, crude oil prices declined by nearly 50% during the fourth quarter of 2014 and continuing into the first quarter of 2015. As of February 20, 2015, NYMEX WTI was approximately $50 per barrel and the three-year forward curve for NYMEX WTI was $61.37 per barrel. In light of the foregoing, projected capital spending and drilling programs by exploration and production companies are expected to dramatically decline.

Given the uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, we have reduced planned capital spending in 2015 by approximately 40% compared to 2014 levels, to $1.2 billion (excluding approximately $120 million of expected capitalized interest and direct internal costs). At this investment level, capital expenditures and cash flows for 2015 are expected to be relatively balanced.

Our primary goals during the next 12 months include:

•preserving liquidity and financial strength;
•
limiting new borrowings and balancing capital investments with cash flows;
•high-grading investments based on rates of return;
•implementing a plan to reduce gross general and administrative expenses by 10% to 15%; and
•implementing a plan to reduce domestic per unit lease operating costs by approximately 5% to 15%.

Our 2015 domestic production, at the mid-point, is expected to be about 48.5 MMBOE, up 8% when adjusted for asset sales during 2014. Including oil production from our recent Pearl development, offshore China, our total company production is expected to increase 18% year-over-year.
Our estimated 2015 capital expenditure budget and estimated production for our strategic plays are shown below:



We are planning to reduce our activity levels in lower-return “held-by-production” areas across our portfolio, allowing for increased investment in the higher-return Anadarko Basin of Oklahoma. Approximately 70% of our planned capital investments in 2015 will be allocated to the Anadarko Basin, which is characterized by resilient economics at lower prices and a deep inventory of drilling opportunities in the SCOOP, STACK and Springer plays. We expect the ongoing reduction of service costs to further enhance returns in these plays. As such, we have elected to significantly slow down our investments in the Uinta Basin, Williston Basin and Eagle Ford plays.

We currently expect to fund 2015 investments through cash flows from operations (inclusive of realized derivative contract gains and losses) and borrowings under our credit facility, as needed. At year-end 2014, more than 85% of our expected 2015 domestic crude oil production was subject to derivative instruments intended to manage the variability associated with future

4

changes in commodity prices. For a complete discussion of our derivative activities, a list of open contracts as of December 31, 2014 and the estimated fair value of those contracts as of that date, see Note 5, “Derivative Financial Instruments,” to our consolidated financial statements in Item 8 of this report.

Our Business Strategy

Despite a reduced capital budget in 2015 that is reflective of the current price environment, our primary, long-term goal continues to be delivering stockholder value through consistent growth of cash flow, production and reserves. Over the past several years, we have refined our asset base and focused our investments on oil and liquids-rich resource plays in the United States. Today, we operate in several U.S. basins with our primary growth area located in the Anadarko Basin. The Anadarko Basin has an extensive inventory of attractive opportunities capable of sustainable growth. Key components of our business strategy include:

Focusing on organic opportunities through disciplined capital investments. While we consider various growth opportunities, including strategic acquisitions, our primary focus is organic growth. Our capital program is designed to allocate investments based on projects that maximize our production and reserve growth at attractive returns.

Continuously improving operations and returns. Controlling the costs to find, develop and produce oil, natural gas and NGLs is critical to creating long-term stockholder value. Our focus areas are characterized by large, contiguous acreage positions and multiple, stacked geologic horizons. As the operator of a majority of our leaseholds, we believe we can consistently increase production and reserves while improving operational efficiencies. For example, in 2014, we reduced our drilling days to total depth by as much as 11% in SCOOP and 24% in STACK, our largest capital investment areas.

Preserving a strong and flexible capital structure. Maintaining a strong capital structure that protects our balance sheet and liquidity is central to our business strategy. For 2015, our goal will be to continue to preserve financial flexibility through strong credit metrics and ample liquidity as we seek to manage the inherent commodity price and operational risks in our industry. As we have done historically, we may adjust our capital program throughout the year, divest non-strategic assets and use derivatives to protect a portion of our future production from commodity price volatility to ensure adequate funds to execute our drilling programs. For example, in 2014, we sold our Granite Wash and other non-strategic assets for approximately $600 million and used the proceeds to redeem our $600 million 7⅛% Senior Subordinated Notes due 2018.

Maintaining a diverse asset base with ongoing portfolio management. Beginning in 2009, we transitioned from a conventional, natural gas-focused company to an unconventional company focused on oil and liquids-rich resource plays in the United States. By maintaining an asset portfolio focused on several key U.S. basins, we increase our flexibility to respond to, and limit our exposure to, the volatility and unique risks our industry faces, such as geologic risks, geographic risks and regional price risks. In line with this element of our strategy and the current weakness in commodity prices, approximately 70% of our 2015 capital investments will be focused on the high-return SCOOP and STACK plays of the Anadarko Basin in Oklahoma.

Executing select, strategic acquisitions and divestitures. We target complementary acquisitions in existing core areas and focus on acquisition opportunities where our operating and technical knowledge is transferable and drilling results can be forecasted with confidence. In addition, from 2012 through 2014, we divested over $2.1 billion in non-strategic assets, supplementing our cash flow and allowing our teams to focus on our core resource plays.

Attracting and retaining quality employees who are aligned with stockholders' interests. We believe in hiring top-tier talent and are committed to our employees' career development. We believe that employees should be rewarded for their performance and that their interests should be aligned with those of our stockholders. As a result, we reward and encourage our employees through performance-based annual compensation and long-term equity-based incentives.

Description of Properties

We have strategically focused on onshore resource plays in the United States. Our domestic plays represent approximately 96% of our proved reserves at year-end 2014. The remaining 4% of our proved reserves are attributable to our offshore developments in China.

Mid-Continent. Approximately 46% of our proved reserves are located in our Mid-Continent region. Our assets are comprised of more than 400,000 net acres in the Anadarko and Arkoma basins where we have over a decade of experience developing the Woodford Shale.


5

Anadarko Basin. We have about 300,000 net acres in the Anadarko Basin. As of December 31, 2014, we had drilled approximately 138 wells in the Anadarko Basin, with wells yielding high volumes of oil and natural gas liquids. Our average net production in the fourth quarter of 2014 was approximately 54,000 BOEPD (27% oil and 34% NGLs), an increase of 118% compared to the fourth quarter of 2013.

Arkoma Basin. We have significant dry gas production from the Arkoma Basin. The area represents approximately 18% of our total consolidated proved reserves. Our investment levels in this area have been significantly curtailed due to low natural gas prices over the past several years. As of December 31, 2014, we had approximately 146,000 net acres in the Arkoma Basin and our net production for the fourth quarter of 2014 was approximately 18,000 BOEPD (99% dry gas). Substantially all of our acreage in this region is held by production.

Rocky Mountains. Approximately 43% of our proved reserves at year end 2014 are located in the Rocky Mountains region. We are assessing and developing our Rocky Mountains region, which is comprised of more than 250,000 net acres in the Williston Basin of North Dakota and Montana as well as the Uinta Basin of Utah. Our assets are primarily oil and are characterized by long-lived production.

Williston Basin. We have approximately 92,000 net acres in the Williston Basin, of which approximately 40,000 acres are being developed in the Bakken and Three Forks plays of North Dakota. Our activities are currently focused on development and we are drilling multi-well pads with lateral lengths as long as 10,000 feet. Fourth quarter 2014 net production averaged approximately 20,000 BOEPD (74% oil and 10% NGLs), representing an increase of 47% compared to the fourth quarter of 2013.

Uinta Basin. We have approximately 225,000 net acres in the Uinta Basin, and our operations can be divided into two areas: the Greater Monument Butte Unit (GMBU) waterflood and an area to the north and adjacent to the GMBU that we refer to as the Central Basin.

Our net production from the Uinta Basin during the fourth quarter of 2014 averaged approximately 25,000 BOEPD (78% oil and 3% NGLs). As of December 31, 2014, we have drilled a combination of 83 vertical and horizontal wells in the Central Basin to hold our acreage. Overall production in the Uinta Basin grew 11% in the fourth quarter of 2014 compared to the fourth quarter of 2013.

Onshore Gulf Coast. About 7% of our proved reserves are located in the onshore Gulf Coast region. We have approximately 25,000 net acres currently in development, most of which are located primarily in Dimmit and Atascosa counties in Texas. Our acreage in the Eagle Ford play produced approximately 11,000 BOEPD (52% oil and 24% NGLs) during the fourth quarter of 2014.

China. Approximately 23 MMBOE, or 4%, of our proved reserves are located in China. Our Pearl facility, located in the South China Sea, is currently producing oil from three wells. An additional four wells are planned that will require net capital investments in 2015 of approximately $40 million. The Pearl facility is expected to reach peak production by mid-2015. Previously, our China assets were included in discontinued operations as they were being marketed for sale. In December 2014, after not being able to obtain an acceptable offer for our China business due to the substantial decline in commodity prices, we decided to retain the assets. Accordingly, the China business was reclassified to continuing operations during the fourth quarter of 2014.

Other. Over the last several years, we slowed our activities in our conventional natural gas plays and have sold numerous non-strategic assets. As of December 31, 2014, our conventional onshore plays in Texas produced approximately 5,700 BOEPD, consisting of 200 BOPD of oil, 300 BOEPD of NGLs and 31 MMcf/d of natural gas. We expect our production in these conventional plays to continue to experience natural declines in 2015 due to limited investment.

Divestitures

Over the last three years, we have divested over $2.1 billion of non-strategic assets in order to re-align our strategic focus toward liquids-rich resource plays in the United States, reduce overall debt and enhance liquidity. In conjunction with our continued portfolio management strategy, we sold or closed the sale of certain assets in 2014 as described below.

Granite Wash. In September 2014, we closed on the sale of our Granite Wash assets, located primarily in Texas, for approximately $588 million (subject to customary purchase price adjustments). We used proceeds from the Granite Wash sale

6

to repay outstanding debt. Please see discussion in Note 4, “Oil and Gas Assets,” to our consolidated financial statements in Item 8 of this report.

Malaysia. In February 2014, Newfield International Holdings, Inc., a wholly-owned subsidiary of the Company, closed the sale of our Malaysia business to SapuraKencana Petroleum Berhad, a Malaysian public company, for $898 million. We used proceeds from the sale of our Malaysia business to fund capital expenditures during 2014. Please see discussion in Note 3, “Discontinued Operations,” to our consolidated financial statements in Item 8 of this report.

Reserves

Estimates of Proved Reserves

All reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. The preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data input into our reserves forecasting and economics evaluation software, as well as multi-discipline management reviews, as described below. The technical employee responsible for overseeing the preparation of the reserves estimates has a Bachelor of Science in Petroleum Engineering, with more than 30 years of experience (including over 20 years of experience in reserve estimation).

Our reserves estimates are made using available geological and reservoir data as well as production performance data. These estimates, made by our petroleum engineering staff, are reviewed annually with management and revised, either upward or downward, as warranted by additional data. The data reviewed includes, among other things, seismic data, well logs, production tests, reservoir pressures, and individual well and field performance data. The data incorporated into our interpretations includes structure and isopach maps, individual well and field performance and other engineering and geological work products such as material balance calculations and reservoir simulation to arrive at conclusions about individual well and field projections. Additionally, offset performance data, operating expenses, capital costs and product prices factor into estimating quantities of reserves. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental regulations, as well as changes in the expected recovery rates associated with development drilling. Sustained decreases in prices, for example, may cause a reduction in some reserves due to reaching economic limits sooner.

Actual quantities of reserves recovered will most likely vary from the estimates set forth below. Reserves and cash flow estimates rely on interpretations of data and require assumptions that may be inaccurate. For a discussion of these interpretations and assumptions, see “Actual quantities of oil, gas and NGL reserves and future cash flows from those reserves will most likely vary from our estimates” under Item 1A, “Risk Factors,” of this report. See “Supplementary Financial Information — Supplementary Oil and Gas Disclosures” in Item 8 of this report for additional reserves disclosures.

At year-end 2014, we had proved reserves of 645 MMBOE, 5% higher than year-end 2013. The table below summarizes our proved reserves by area at December 31, 2014.
 
 
Proved Reserves
 
Percentage of
Proved Reserves
 
 
(MMBOE)
 
 
Domestic:
 
 
 
 
Mid-Continent
 
294

 
46
%
Rocky Mountains

280


43
%
Onshore Gulf Coast
 
48

 
7
%
Total Domestic
 
622

 
96
%
International:
 
 
 
 
China
 
23

 
4
%
Total
 
645

 
100
%
 

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The following table shows by country and in the aggregate a summary of our proved oil and gas reserves as of December 31, 2014.
 
 
Oil and
Condensate
 
Natural
Gas
 
NGLs
 
Total
 
 
(MMBbls)
 
(Bcf)
 
(MMBbls)
 
(MMBOE)
Proved Developed Reserves:
 
 
 
 
 
 
 
 
Domestic
 
135

 
938

 
38

 
329

China
 
9

 
—

 
—

 
9

Total Proved Developed
 
144

 
938

 
38

 
338

Proved Undeveloped Reserves:
 
 
 
 
 
 
 
 
Domestic
 
143

 
669

 
38

 
293

China
 
14

 
—

 
—

 
14

Total Proved Undeveloped
 
157

 
669

 
38

 
307

Total Proved Reserves
 
301

 
1,607

 
76

 
645



Total Proved Reserves    

Our estimates of proved reserves and related PV-10 and standardized measure of future net cash flows as of December 31, 2014 are calculated based upon SEC pricing, which uses a twelve-month unweighted average first-day-of-the-month oil and natural gas benchmark prices, adjusted for marketing and other differentials. The prices of crude oil, domestic natural gas and NGLs have declined substantially since June 2014. Sustained lower prices will result in future SEC pricing being substantially lower, which, absent significant proved reserve additions and/or cost reductions, will reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations.

Our year-end 2014 proved reserves of 645 MMBOE consisted of 291 MMBOE proved developed producing, 47 MMBOE proved developed non-producing and 307 MMBOE proved undeveloped reserves. Our proved liquids reserves at year-end 2014 were 377 million barrels, compared to 338 million barrels at year-end 2013, an increase of 12%. During 2014, oil and condensate reserves increased 31 million barrels and NGL reserves increased 8 million barrels. At year-end 2014, 80% of our proved liquids reserves were crude oil or condensate. At December 31, 2014, our proved natural gas reserves were 1,607 Bcf, which represented a decrease of 2% compared to 2013.

During 2014, we added 72 MMBOE through extensions, discoveries and other additions. Consistent with our continued focus on domestic liquids, our 2014 additions were 99% domestic and 74% were liquids, which was 42 million barrels of oil and 12 million barrels of NGLs. Through infill drilling revisions, we added 77 MMBOE. At December 31, 2014, the SEC pricing for natural gas was $4.35 per MMBtu, a 19% increase compared to the prior year-end, and pricing for oil was $94.98 per barrel, a 2% decrease compared to the prior year-end. As a result, we revised our total proved reserves upward by 3 MMBOE for pricing changes. During 2014, we purchased 9 MMBOE and divested 49 MMBOE. Divestitures included 38 MMBOE in the Granite Wash and 10 MMBOE in Malaysia. During 2014, we had a negative 29 MMBOE performance revision primarily associated with the Arkoma Woodford, the Greater Monument Butte Unit and the Uinta's Wasatch formation.

Proved Undeveloped Reserves  

Our proved undeveloped reserves at December 31, 2014 were 307 MMBOE compared to 275 MMBOE at December 31, 2013. Liquids comprised 64% of our total proved undeveloped reserves as of December 31, 2014. During 2014, we invested approximately $0.8 billion of drilling, completion and facilities-related capital to convert 60 MMBOE of our December 31, 2013 proved undeveloped reserves into proved developed reserves. During 2014, we added 52 MMBOE of new proved undeveloped reserves through discoveries, extensions and other additions. In 2014, we had positive revisions of 34 MMBOE that were primarily related to successful infill drilling in our large onshore areas such as the Anadarko Basin offset by development plan updates. During 2014, we had a 6 MMBOE net increase due to sales and acquisitions. We continually assess the economic viability of our proved undeveloped reserves and direct capital resources to develop the areas that will provide the greatest stockholder value.

Proved undeveloped reserve quantities are limited by the activity level of development drilling we have intent to undertake during the 2015-2019 five-year period. We have estimated capital expenditures of approximately $575 million to develop our

8

proved undeveloped reserves in 2015 in our reserve report as of December 31, 2014, which is consistent with our 2015 capital budget. Of the 307 MMBOE of proved undeveloped reserves at December 31, 2014, 39 MMBOE is associated with the Greater Monument Butte waterflood and exceed five years from the date of first booking. The waterflood requires the timely and orderly drilling of production and water injection wells, conversion of producing wells to injection wells and the injection of certain amounts of water before all producing wells are drilled to optimize oil recovery and project economics. For additional information regarding the changes in our proved reserves, see our "Supplementary Financial Information — Supplementary Oil and Gas Disclosures" under Item 8 of this report.

During the years 2012, 2013 and 2014, we developed 9%, 12% and 22%, respectively, of our prior year-end proved undeveloped reserves. The development plans in our year-end reserve report reflect (i) the allocation of capital to projects in the first year of activity based upon the initial budget for such year and (ii) in subsequent years, the capital allocation in our five-year business plan, each of which generally is governed by our expectations for capital investment in such time period. Changes in commodity pricing between the time of preparation of the reserve report and actual investment, investment alternatives that may have been added to our portfolio of assets, changes in the availability and costs of oilfield services, and other economic factors may lead to changes in our development plans. As a result, the future rate at which we develop our proved undeveloped reserves may vary from historical development rates. Continued sustained low oil and natural gas prices through 2015 could also render some of our proved undeveloped reserves uneconomic at SEC pricing or compel us to reevaluate our project commitments to certain development projects.

Reserves Sensitivities

Our year-end 2014 reserve estimates were prepared using SEC pricing for crude oil of $94.98 per barrel and natural gas of $4.35 per MMBtu. The current forward curve for commodity prices is materially lower compared to year-end 2014 SEC pricing; therefore, the following sensitivity table is provided to illustrate the estimated impact on our proved reserve volumes and value. In addition to different price assumptions, the sensitivities below include assumed capital and expense reductions we expect to realize at lower commodity prices. The reduction in proved reserve volumes is attributable to reaching the economic limit sooner. The proved undeveloped change in volumes is a result of well locations no longer meeting our investment criteria as well as reaching the economic limit sooner.

These sensitivity cases are only to demonstrate the impact that a lower price and cost environment may have on reserves volumes and PV-10. There is no assurance that these prices or cost savings will actually be achieved.
 
 
Actual at December 31, 2014
 
 
Sensitivity A
 
 
Sensitivity B
Crude oil price (per Bbl)
$
94.98(1)

 
$
70.00(2)

 
$
60.00(2)

Natural gas price (per MMBtu)
$
4.35(1)

 
$
4.00(2)

 
$
3.50(2)

 
 
 
 
 
 
 
 
 
Capital expenditure reduction
 
n/a

 
 
25
%
 
 
25
%
Operating expense reduction
 
n/a

 
 
15
%
 
 
15
%
 
 
 
 
 
 
 
 
 
Proved developed reserves (MMBOE)
 
338

 
 
335

 
 
328

Proved undeveloped reserves (MMBOE)
 
307

 
 
299

 
 
266

Total proved reserves (MMBOE)
 
645

 
 
634

 
 
594

 
 
 
 
 
 
 
 
 
Proved reserve PV-10 value (before tax, in millions)
$
8,787

 
$
6,210

 
$
4,472

Present value of future income tax expense
 
2,575

 
 
1,399

 
 
713

Standardized measure of discounted future net cash flows
$
6,212

 
$
4,811

 
$
3,759

_________________
(1) SEC pricing before adjustment for market differentials.
(2) Prices represent potential SEC pricing based on different pricing assumptions before adjustment for market differentials.

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. We and others in the oil and natural gas industry

9

use PV-10 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 PV-10 to the standardized measure:
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China
 
Malaysia
 
Total
 
 
(In millions)
December 31, 2014:
 
 
 
 
 
 
 
 
Proved reserve PV-10 value (before tax)
 
$
7,723

 
$
1,064

 
$
—

 
$
8,787

Present value of future income tax expense
 
2,393

 
182

 
—

 
2,575

Standardized measure of discounted future net cash flows
 
$
5,330

 
$
882

 
$
—

 
$
6,212

 
 
 
 
 
 
 
 
 
December 31, 2013:
 
 
 
 
 
 
 
 
Proved reserve PV-10 value (before tax)
 
$
6,637

 
$
1,135

 
$
303

 
$
8,075

Present value of future income tax expense
 
2,009

 
233

 
—

 
2,242

Standardized measure of discounted future net cash flows
 
$
4,628

 
$
902

 
$
303

 
$
5,833


Reserves Concentration

The table below sets forth the concentration of our proved reserves attributable to our largest fields (those whose reserves are greater than 15% of our total proved reserves). Our largest fields by volume, SCOOP, the Greater Monument Butte Unit and Arkoma Woodford Shale, accounted for approximately 48% of the total net present value of our proved reserves at December 31, 2014. 
 
 
Percentage of
Proved Reserves
10 largest fields
 
91%
3 largest fields
 
61%
Largest Fields.    The table below sets forth the annual production volumes, average realized prices and related production cost structure on a per unit-of-production basis for our largest fields. For a discussion regarding our total domestic and international annual production volumes, average realized prices, related cost structure and information about our contractual obligations and delivery commitments, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which disclosure is incorporated herein by reference.

10

 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Production:
 
 
 
 
 
 
Crude oil and condensate (MBbls)
 
 
 
 
 
 
SCOOP
 
2,548

 
1,323

 
379

Greater Monument Butte Unit
 
4,062

 
3,764

 
3,720

Arkoma Woodford Shale
 
44

 
65

 
130

Natural gas (Bcf)
 
 
 
 
 
 
SCOOP
 
34.5

 
16.8

 
5.1

Greater Monument Butte Unit
 
1.2

 
0.5

 
1.9

Arkoma Woodford Shale
 
41.7

 
51.7

 
63.2

NGLs (MBbls)
 
 
 
 
 
 
SCOOP
 
4,762

 
1,888

 
653

Greater Monument Butte Unit
 
150

 
152

 
133

Arkoma Woodford Shale
 
67

 
75

 
86

Total production by field (MBOE)
 
 
 
 
 
 
SCOOP
 
13,066

 
5,999

 
1,857

Greater Monument Butte Unit
 
4,411

 
4,001

 
4,172

Arkoma Woodford Shale
 
7,057

 
8,746

 
10,755

 
 
 
 
 
 
 
Average Realized Prices:(1)
 
 
 
 
 
 
Crude oil and condensate (per Bbl)
 
 
 
 
 
 
SCOOP
 
$
85.66

 
$
93.75

 
$
86.03

Greater Monument Butte Unit
 
74.40

 
78.24

 
77.58

Arkoma Woodford Shale
 
90.44

 
93.71

 
90.54

Natural gas (per Mcf)
 
 
 
 
 
 
SCOOP
 
$
3.96

 
$
3.35

 
$
2.33

Greater Monument Butte Unit
 
4.09

 
4.74

 
1.71

Arkoma Woodford Shale
 
4.08

 
3.31

 
2.35

NGLs (per Bbl)
 
 
 
 
 
 
SCOOP
 
$
29.54

 
$
31.62

 
$
25.16

Greater Monument Butte Unit
 
48.33

 
52.26

 
63.92

Arkoma Woodford Shale
 
19.11

 
20.62

 
27.64

Average realized prices by field (per BOE)
 
 
 
 
 
 
SCOOP
 
$
37.94

 
$
40.01

 
$
32.73

Greater Monument Butte Unit
 
71.27

 
76.20

 
71.99

Arkoma Woodford Shale
 
24.82

 
20.43

 
15.14

 
 
 
 
 
 
 
Average Production Cost:
 
 
 
 
 
 
SCOOP (per BOE)
 
$
4.58

 
$
4.38

 
$
4.59

Greater Monument Butte Unit (per BOE)
 
25.68

 
24.14

 
16.48

Arkoma Woodford Shale (per BOE)
 
14.82

 
12.62

 
10.80

_________________
(1) Does not include impact of derivative gains or losses.


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Drilling Activity

The following table sets forth the number of oil and gas wells that completed drilling for each of the last three years. 
 
 
2014
 
2013
 
2012
 
 
Gross  
 
Net  
 
Gross  
 
Net  
 
Gross  
 
Net
Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
 
Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
254

 
114

 
297

 
118

 
263

 
135

Nonproductive
 
—

 
—

 
1

 
1

 
2

 
2

China:
 
 
 
 
 
 
 
 
 
 
 
 
Nonproductive
 
1

 
1

 
1

 
1

 
—

 
—

Malaysia:(1)
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
—

 
—

 
2

 
1

 
—

 
—

Nonproductive
 
—

 
—

 
—

 
—

 
2

 
1

Exploratory well total
 
255

 
115

 
301

 
121

 
267

 
138

Development wells:
 
 
 
 
 
 
 
 
 
 
 
 
Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
326

 
231

 
237

 
184

 
240

 
195

China:
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
2

 
1

 
3

 
1

 
—

 
—

Malaysia:(1)
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
—

 
—

 
12

 
8

 
12

 
8

Development well total
 
328

 
232

 
252

 
193

 
252

 
203

 _________________
(1)
Classified as discontinued operations.
We were in the process of drilling 20 gross (15 net) development wells domestically at December 31, 2014. In China we were drilling one gross (one net) development well at December 31, 2014.

12

Productive Wells

As of December 31, 2014, we had the following productive oil and gas wells.
 
 
Company
Operated Wells
 
Outside
Operated Wells
 
Total
Productive Wells
 
 
Gross  
 
Net  
 
Gross  
 
Net  
 
Gross  
 
Net  
Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
2,651

 
2,153

 
903

 
78

 
3,554

 
2,231

Natural gas
 
1,170

 
909

 
1,182

 
167

 
2,352

 
1,076

China:
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
2

 
1

 
42

 
5

 
44

 
6

Total:
 
 
 
 
 
 
 
 
 
 
 
 
Oil
 
2,653

 
2,154

 
945

 
83

 
3,598

 
2,237

Natural gas
 
1,170

 
909

 
1,182

 
167

 
2,352

 
1,076

Total
 
3,823

 
3,063

 
2,127

 
250

 
5,950

 
3,313


The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements or production sharing contracts. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions.

Acreage Data

The following two tables list by geographic area interests we owned in developed and undeveloped oil and gas acreage at December 31, 2014, along with a summary by year of our undeveloped acreage scheduled to expire in the next five years. In most cases, the drilling of a commercial well, or the filing and approval of a development plan or suspension of operations will hold the acreage beyond the expiration date. Domestic ownership interests are onshore and generally take the form of “working interests” in oil and gas leases that have varying terms. International ownership interests are offshore and generally arise from participation in PSCs.
 
Total Acreage
 
 
Developed Acres
 
Undeveloped Acres
 
 
Gross
 
Net
 
Gross
 
Net
 
 
(In thousands)
Domestic:
 
 
 
 
 
 
 
 
Mid-Continent
 
814

 
286

 
344

 
210

Rocky Mountains
 
280

 
196

 
470

 
324

Onshore Gulf Coast
 
305

 
217

 
29

 
26

Total Domestic
 
1,399

 
699

 
843

 
560

China:
 
34

 
9

 
—

 
—

Total
 
1,433

 
708

 
843

 
560


Expiring Acreage 
 
 
Undeveloped Acres Expiring
 
 
2015
 
2016
 
2017
 
2018
 
2019
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
 
(In thousands)
Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mid-Continent
 
62

 
39

 
70

 
40

 
37

 
24

 
1

 
—

 
—

 
—

Rocky Mountains
 
106

 
73

 
86

 
37

 
77

 
68

 
7

 
3

 
11

 
10

Onshore Gulf Coast
 
14

 
14

 
—

 
—

 
2

 
2

 
—

 
—

 
—

 
—

Total
 
182

 
126

 
156

 
77

 
116

 
94

 
8

 
3

 
11

 
10


13

 
At December 31, 2014, we owned fee mineral interests in 557,626 gross (121,561 net) acres. These interests do not expire.

Title to Properties

We believe that we have satisfactory title to substantially all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes, development obligations under oil and gas leases or capital commitments under our PSCs in China. Prior to acquiring undeveloped properties, we endeavor to perform a title investigation that is thorough but less vigorous than that we endeavor to conduct prior to drilling, which is consistent with standard practice in the oil and gas industry. Generally, before we commence drilling operations on properties that we operate, we conduct a title examination and perform curative work with respect to significant defects that we identify. We believe that we have performed title examination with respect to substantially all of our active properties that we operate.

Marketing

Substantially all of our oil, natural gas and NGLs are sold at market-based prices to a variety of purchasers, primarily under short-term contracts (less than 12 months). We also have long-term contracts in the Uinta Basin at market-based prices, less a variable differential that becomes fixed below certain market price thresholds. For a list of purchasers of our production that accounted for 10% or more of our total revenues for the three preceding calendar years, please see Note 1, “Organization and Summary of Significant Accounting Policies — Major Customers,” to our consolidated financial statements in Item 8 of this report, which information is incorporated herein by reference. We believe that the loss of any of these purchasers would not have a material adverse effect on us because alternative purchasers are available.

Historically, our access to refining capacity outside of the Salt Lake City area has been restricted due to limited transportation and refining options because of the paraffin content of our Uinta Basin production. As such, we have two long-term agreements with two refineries in the Salt Lake City area that run through 2020 and 2025. These agreements require us to deliver a combined 38,000 BOPD of crude oil. Since these agreements were entered into, developments in rail transportation in the area have reduced our dependence on the Salt Lake City refiners. Please see the discussion regarding potential delivery commitment shortfalls related to these agreements under "Contractual Obligations" in Item 7 of this report.

Competition

Competition in the oil and gas industry is intense, particularly with respect to the hiring and retention of technical personnel, the acquisition of properties and access to drilling rigs and other services. Please see the discussion under “Competition for, or the loss of, our senior management or experienced technical personnel may negatively impact our operations or financial results” and “Competition in the oil and gas industry is intense” in Item 1A of this report, which information is incorporated herein by reference.

Segment Information

For more information on our continuing operations by segment, see Note 14, “Segment Information,” to our consolidated financial statements in Item 8 of this report.

14


Employees

As of February 20, 2015, we had 1,331 employees. All but 61 of our employees were located in the United States. None of our employees are covered by a collective bargaining agreement. We believe that relationships with our employees are satisfactory.

Regulation

Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, provincial, tribal, local, foreign and international regulations. An overview of these regulations is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen resource or environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Please see the discussion under the caption “We are subject to complex laws and regulatory actions that can affect the cost, manner, feasibility or timing of doing business,” in Item 1A of this report.

General Overview.    Our oil and gas operations are subject to various federal, state, provincial, tribal, local, foreign and international laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

•
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.

Federal Regulation of Drilling and Production.    Many of our domestic oil and gas leases are granted by the federal government and administered by the BSEE, ONRR or the BLM, all federal agencies. BLM leases contain relatively standardized terms and require compliance with detailed BLM, BSEE and ONRR regulations. Many onshore leases contain

15

stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the time during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban surface activity. Under certain circumstances, the BLM or the BSEE, as applicable, may require that our operations on federal leases be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and results of operations.

State and Local Regulation of Drilling and Production.   We own interests in properties located onshore in a number of states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, disclosure of hydraulic fracturing fluid composition, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.

Environmental Regulations.    We are subject to various federal, state, provincial, tribal, local, foreign and international laws and regulations concerning occupational safety and health, oil and gas production, as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:

•
assessing the environmental impact of seismic acquisition, drilling or construction activities;
•
the generation, storage, transportation and disposal of waste materials and flowback or produced water;
•
the emission of certain gases or materials into the atmosphere;
•
the construction and placement of wells;
•
the 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; and
•
protection of private and public surface and ground water supplies.

We consider the costs of environmental regulatory compliance and protection and safety and health compliance necessary and manageable parts of our business. We have been able to plan for and comply with environmental regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increased stringency, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and will likely continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters and the cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations).

Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted or banned by governmental authorities. Moreover, some environmental laws and regulations may impose strict liability regardless of fault or knowledge, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent future laws or regulations are implemented or other governmental action is taken that prohibits, restricts or materially increases the costs of onshore or offshore drilling, or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

Discharges to waters of the U.S. are further regulated and limited under the federal Clean Water Act (“CWA”) and analogous state and tribal laws. The CWA prohibits any discharge of pollutants into waters of the United States except in

16

compliance with permits issued by federal and state governmental agencies. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure or “SPCC” plans. We have such plans in place and have made changes as necessary due to regulatory changes by the U.S. Environmental Protection Agency, also known as the “EPA,” that became effective in November 2009.

The National Environmental Policy Act, or NEPA, requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. Compliance with this requirement may lead to additional costs and delays in permitting for operators as the BLM may need to prepare additional Environmental Assessments and more detailed Environmental Impact Statements, which would be available for public review and comment. In addition, the White House Council on Environmental Quality recently issued draft guidance requiring consideration of climate change impacts in NEPA reviews, which may result in requirements to deploy additional air pollution control measures. These additional requirements could increase our compliance costs.

The Endangered Species Act restricts activities that may affect federally-identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal or permanent ban on operations in affected areas. Similarly, the Migratory Bird Treaty Act, or MBTA, implements various treaties and conventions between the U.S. and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas.

The Resource Conservation and Recovery Act, or RCRA, generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

The Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible parties” may be subject to joint and several liability under the Superfund law for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease onshore properties that have been used for the exploration and production of oil and natural gas for a number of years. Many of these onshore properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and any wastes that may have been disposed or released on them may be subject to the Superfund law, RCRA and analogous state laws and common law obligations, and we potentially could be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination.

The Clean Air Act, or CAA, and comparable state statutes regulate and limit the emission of air pollutants by the Company and affect our oil and gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed and continues to develop more stringent regulations governing emissions of toxic air pollutants, and is considering the expanded regulation of existing air pollutants and additional air pollutants. In addition, the EPA promulgated regulations that are designed to reduce the emission of volatile organic chemicals (VOCs) and that will require oil and gas companies by 2015 to utilize “green completions” to capture VOCs and other air pollutants when natural gas wells are fracked. Such regulations may increase the costs of compliance for some facilities or the market price for oil and natural gas.

In addition, while the federal Safe Drinking Water Act, or SDWA, generally excludes hydraulic fracturing from the definition of underground injection, it does not exclude hydraulic fracturing involving the use of diesel fuels. In 2014, the EPA issued draft permitting guidance governing hydraulic fracturing with diesel fuels. While we do not use diesel fuels in our hydraulic fracturing fluids, we may become subject to federal permitting under SDWA if our fracturing formula changes. In addition, the SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans.


17

The Occupational Safety and Health Act, or OSHA, and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

For more than a decade, Congress has been considering a variety of sectoral or economy-wide market-based tax, energy or environmental mechanisms to regulate or induce the reduction of emissions of greenhouse gases by several commercial or industrial sectors. In June of 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009. In addition, more than one-third of the states have implemented some form of legal measure to regulate or reduce emissions of greenhouse gases. On April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the CAA. On December 7, 2009, the EPA responded to the Massachusetts, et al. v. EPA decision with an “endangerment finding” for greenhouse gases emitted from certain mobile sources. The EPA finding concluded that such GHG emissions “cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare” and contribute to the threat of climate change.

In 2013, the United States Court of Appeals for the District of Columbia Circuit upheld, in Coalition for Responsible Regulation, Inc. v. EPA, the EPA endangerment finding. On October 15, 2013, the United States Supreme Court declined to review the EPA’s endangerment finding or its underlying scientific conclusions, as well as the regulations governing emissions of GHGs from motor vehicles, but granted review on several stationary source permitting issues under the CAA. By leaving the endangerment finding undisturbed, the Court has effectively affirmed the EPA’s authority to regulate GHGs under the CAA.

In June 2013, the President of the United States released a Climate Action Plan which sets forth a series of executive actions the current administration intends to undertake to address climate change. The Climate Action Plan includes a two-part directive that the EPA promulgate rules to regulate GHG emissions from new and existing fossil fuel power plants on a defined schedule and consider employing market-based mechanisms. Specifically, the President issued a Presidential Memorandum directing the EPA to propose and timely finalize carbon emission standards for certain new fossil fuel power plants under Section 111(b) of the CAA, and to propose carbon emission “standards, regulations or guidelines” for existing fossil fuel power plants under Section 111(d) of the CAA. The EPA intends to promulgate final carbon standards for new and existing fossil fuel power plants by mid-2015. The rule for existing sources, in particular, may require states to develop plans to maintain “greenhouse gas budgets” under certain thresholds. As a result, states may seek to impose additional air requirements on oil and gas operations to meet these budgets. The EPA also announced in January 2015 that it would be issuing methane regulations for the oil and gas industry by mid-2015. We do not yet know what such regulations would require or how they might impact our operations.

Several other federal agencies and state governments are considering or have already implemented rules to regulate, monitor, or induce market reductions of GHG emissions. It is not possible at this time, however, to predict the applicability or stringency of future GHG mitigation regulations for the oil and gas industry, if at all, or how any new legislation or regulations would impact our business. Any such future federal laws and regulations could affect oil and natural gas commodity market pricing, and result in increased costs of compliance, or additional operating restrictions. Any additional costs or operating restrictions associated with GHG legislation or regulations could have material adverse effects on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.

In addition, federal, state, tribal and local agencies are considering or have already implemented regulations related to hydraulic fracturing. Hydraulic fracturing involves using water, sand, and certain chemicals pumped at high pressure to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The hydraulic-fracturing process is typically regulated by state oil and natural gas agencies, although the EPA and other federal regulatory agencies have taken steps to impose federal regulatory requirements. Certain states in which we operate or own interests, such as Texas, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether.

For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process, and the RCT adopted rules regarding the same in December 2011. We currently voluntarily disclose all chemicals used in our hydraulic fracturing through FracFocus (http://fracfocus.org), the national hydraulic fracturing chemical registry managed by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission, two organizations whose missions both revolve around conservation and environmental protection. Nevertheless, in May 2014, the EPA published an Advanced Notice of Proposed Rulemaking under the Toxic Substances Control Act to develop a federal approach to obtain information on chemical substances and mixtures used in hydraulic fracturing.


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Federal Regulation of Sales and Transportation of Natural Gas.    Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act, or NGA, and by regulations and orders promulgated under the NGA by the FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

Pursuant to authority delegated to it by the Energy Policy Act of 2005, or EPAct 2005, FERC promulgated anti-manipulation regulations establishing violation enforcement mechanisms which make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to use or employ any device, scheme, or artifice to defraud, to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or to engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any entity. Violation of these requirements, similar to violations of other NGA and FERC enforcement authorities, may be subject to investigation and penalties of up to $1 million per day per violation. FERC may also order disgorgement of profit and corrective action. We believe, however, that neither the EPAct 2005 nor the regulations promulgated by FERC as a result of the EPAct 2005 will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.

Our sales of oil and natural gas are also subject to anti-manipulation and anti-disruptive practices authority under the Commodity Exchange Act, or CEA, as amended by the Dodd-Frank Wall Street Reform Act and Consumer Reform Act (the Dodd-Frank Act), and regulations promulgated thereunder by the Commodity Futures Trading Commission, or CFTC. The CEA, as amended by the Dodd-Frank Act, prohibits any person from using or employing any manipulative or deceptive device in connection with any swap, or a contract of sale of any commodity, or for future delivery on such commodity, in contravention of the CFTC’s rules and regulations. The CEA, as amended by the Dodd-Frank Act, also prohibits knowingly delivering or causing to be delivered false or misleading or inaccurate reports concerning market information or conditions that affect or tend to affect the price of any commodity.

The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the EPA, the FERC, the CFTC and the courts. The natural gas industry historically has been very heavily regulated. In the past, the federal government regulated the prices at which natural gas could be sold. Congress removed all price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. There is always some risk, however, that Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action the FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by the FERC and Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil.    Our sales of crude oil and condensate are currently not regulated. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of transportation service on certain petroleum products pipelines. However, we do not believe that these regulations affect us any differently than other crude oil and condensate producers. In addition, certain emergency orders issued in 2014 by the U.S. Department of Transportation imposed additional restrictions on the shipment of crude oil by rail from the Bakken Shale. These new restrictions may increase our costs of transporting our production from the Bakken.

International Regulations.    Our exploration and production operations in China are subject to various types of regulations similar to those described above. These regulations are imposed by various agencies under the People's Republic of China (PRC). For example, laws under the Provisional Regulations on Administration and Management of the Abandonment of Offshore Oil and Gas Producing Facilities enacted in 2010, regulate our development and production activities offshore China. There are several departments in charge of aspects of energy industry regulation in China, including, the Bureau of Energy, the Ministry of Land and Resources, the Ministry of Housing and Urban-Rural Development, the State Administration of Work Safety, the Ministry of Environmental Protection, and the State Bureau of Tax. The PRC continues to develop environmental laws, regulations and controls surrounding offshore developments. In many cases, the legal requirements may be similar in form to the U.S. regulations; however, they impose additional or more stringent conditions or controls that can significantly alter or delay the development of a project or substantially increase the cost of doing business in China.

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Financial Information

Financial information regarding the geographic areas in which we operate is incorporated herein by reference to Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, “Financial Statements and Supplementary Data.” Risks associated with our international operations are discussed under Item 1A, "Risk Factors," which information is incorporated herein by reference.

Commonly Used Oil and Gas Terms

Below are explanations of some commonly used terms in the oil and gas business and in this report.

Barrel or Bbl.    One stock tank barrel or 42 U.S. gallons liquid volume.

Basis risk.    The risk associated with the sales point price for oil or gas production varying from the reference (or settlement) price for a particular derivative transaction.

Bcf.    Billion cubic feet.

Bcfe.    Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

BLM.    The Bureau of Land Management of the United States Department of the Interior.

BOE.    One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate or 42 gallons for NGLs.

BOEPD.    Barrels of oil equivalent per day.

BOPD.    Barrels of oil per day.

BSEE.    Bureau of Safety and Environmental Enforcement.

Btu.    British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion.    The installation of permanent equipment for the production of oil or natural gas.

Developed acres.    The number of acres that are allocated or assignable to producing wells or wells capable of production.

Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploitation activities.    An exploration well drilled to find and produce probable reserves. Exploitation wells typically have less risk and less reserve potential and may be drilled at a lower cost than other exploration wells. Most of the exploitation wells we drill are located in the Mid-Continent or the Monument Butte field. For internal reporting and budgeting purposes, we combine exploitation and development activities.

Exploration well.    An exploration well is a well drilled to find a new field or new reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well. For internal reporting and budgeting purposes, we exclude exploitation activities from exploration activities.

FERC.    The Federal Energy Regulatory Commission.

Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

FPSO.    A floating production, storage and off-loading vessel commonly used overseas to produce oil from locations where pipeline infrastructure is not available.


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Gross acres or gross wells.    The total acres or wells in which we own a working interest.

Infill drilling or infill well.    A well drilled between known producing wells to improve oil and gas reserve recovery efficiency.

Liquids. Crude oil and NGLs.

Liquids-rich.    Formations that contain crude oil or NGLs instead of, or as well as, natural gas.

MBbls.    One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE.    One thousand barrels of oil equivalent.

Mcf.    One thousand cubic feet of natural gas.

Mcfe.    One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

MMBbls.    One million barrels of crude oil or other liquid hydrocarbons.

MMBOE.    One million barrels of oil equivalent, which includes crude oil and condensate, NGLs and natural gas. One MMBOE equals six Bcf.

MMBtu.    One million Btus.

MMcf.    One million cubic feet of natural gas.

MMcf/d.    One million cubic feet of natural gas produced per day.

MMcfe.    One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

MMMBtu.    One billion Btus.

Net acres or net wells.    The sum of the fractional working interests we own in gross acres or gross wells.

NGL.    Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasolines.

NYMEX.    The New York Mercantile Exchange.

NYMEX Henry Hub.    The major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub Index.

ONRR.    Office of Natural Resources Revenue.

Probable reserves.    Those additional reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered. The SEC provides a complete definition of probable reserves in Rule 4-10(a)(18) of Regulation S-X.

Productive well.    A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves.    In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.


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Proved reserves.    Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves.    In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

PV-10. The pre-tax present value of estimated future gross revenues from the production of proved reserves, based on year-end SEC pricing, net of estimated future production, development and abandonment costs, based on year-end costs, discounted at an annual discount rate of 10%. After-tax PV-10 is referred to as the standardized measure.

Reserve life index.    This index is calculated by dividing total proved reserves on an equivalent basis at year-end by annual production to estimate the number of years of remaining production.

Resource play.    A play targeting tight sand, coal bed or shale reservoirs. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require horizontal drilling and stimulation treatments or other special recovery processes in order to be produced economically.

SCOOP. South-Central Oklahoma Oil Province. A field in the Anadarko Basin of Oklahoma in which we operate.

SEC pricing.    The unweighted average first-day-of-the-month commodity price for crude oil (WTI) or natural gas (NYMEX) for the prior 12 months, adjusted for market differentials. The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule).

STACK. Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate.

Tcf. One trillion cubic feet of natural gas.

Undeveloped acreage.    Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest.    The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI.    West Texas Intermediate, a grade of crude oil.

Additional Information

Through our website, www.newfield.com, you can access electronic copies of our governing documents free of charge, including our Board of Directors’ Corporate Governance Guidelines and the charters of the committees of our Board of Directors. In addition, through our website, you can access the documents we file with the U.S. Securities and Exchange Commission (SEC), including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments thereto, as soon as reasonably practicable after we file or furnish them. You also may request printed copies of our SEC filings or governance documents, free of charge, by writing to our corporate secretary at the address on the cover of this report. Information contained on our website is not incorporated herein by reference and should not be considered part of this report.

In addition, the public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.


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Our corporate headquarters are located at 4 Waterway Square Place, Suite 100, The Woodlands, Texas 77380, and our telephone number is (281) 210-5100.

Item 1A. Risk Factors

There are many factors that may affect Newfield’s business and results of operations. Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. You should carefully consider, in addition to the other information contained in this report, the risks described below.

Oil, gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse impact on our business. Our revenues, profitability and future growth, as well as liquidity and ability to access additional sources of capital, depend substantially on prevailing prices for oil, gas and NGLs. Sustained lower prices will reduce the amount of oil, natural gas and NGLs that we can economically produce. Oil, natural gas and NGL prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

The markets for oil, gas and NGLs have historically been, and will likely remain, volatile. For example, record high U.S. crude oil production has contributed to global oil supply exceeding demand, which has caused crude oil prices to drop precipitously since September 2014. The price of crude oil (WTI) in January 2015 averaged approximately $47 per barrel, as compared to approximately $95 per barrel in January 2014. Natural gas prices also experienced significant volatility during 2014, as the NYMEX Henry Hub natural gas price ranged from a high of $6.15 per MMBtu (the highest price since December 2008) to a low of $2.89 per MMBtu (on the last trading day of the year).

The market prices for crude oil, natural gas and NGLs depend on factors beyond our control. Among the factors that can cause fluctuations are:

•
the domestic and foreign supply of, and demand for, oil, natural gas and NGLs;
•
world-wide economic conditions;
•
the level and effect of trading in commodity futures markets, including commodity price speculators and others;
•
political conditions in oil and gas producing regions;
•
the actions taken by foreign oil and gas producing nations;
•
the actions taken by the Organization of Petroleum Exporting Countries;
•
the price and availability of, and demand for, alternative fuels;
•
weather conditions and climate change;
•
world-wide conservation measures;
•
technological advances affecting energy consumption;
•
the price and level of foreign imports;
•
potential U.S. exports of oil and/or NGLs;
•
the availability, proximity and capacity of transportation and processing facilities;
•
the costs of exploring for, developing, producing, transporting and marketing oil, gas and NGLs; and
•
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulation.

While we cannot predict whether or for how long commodity prices will remain at this level or decline further, we have made adjustments in response to the current strong supply and soft demand, such as modifying our 2015 capital investment plan based on commodity prices, drilling success, and markets for our products. These adjustments are likely to influence our profitability and could adversely affect our business, financial condition and results of operations. In addition, our stock price in the market is influenced by oil and gas price movements.

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Sustained material declines in crude oil, natural gas or NGL prices may have the following effects on our business:

•
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 develop the leases prior to expiration;
•reduce reserves and the amount of products we can economically produce;
•reduce revenues, income and cash flows; or
•reduce the carrying value of our assets in our balance sheet through ceiling test impairments.

We have substantial capital requirements to fund our business plans that could be greater than cash flows from operations. Limited liquidity would likely negatively impact our ability to execute our business plan.    We anticipate that our 2015 capital investment levels will approximate our cash flows from operations (inclusive of realized derivative contract gains and losses). We expect to use available capacity under our credit arrangements to fund any shortfall. Our ability to generate operating cash flows is subject to many risks and variables, such as the level of production from existing wells; prices of natural gas, oil and NGLs; our success in developing and producing new reserves and the other risk factors discussed herein. Actual levels of capital expenditures may vary significantly due to many factors including drilling results, commodity prices, industry conditions, the prices and availability of goods and services, the extent to which properties are acquired and the promulgation of new regulatory requirements. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We may have to reduce capital expenditures, and our ability to execute our business plans could be adversely affected, if:

•we are unable to access the capital markets at a time when we would like, or need, to raise capital;
•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 fossil fuel companies;
•our customers or working interest owners default on their obligations to us; or
•we are unable to sell non-strategic assets at acceptable prices due to low commodity prices.

Actual quantities of oil, natural gas and NGL reserves and future cash flows from those reserves will most likely vary from our estimates.    Estimating accumulations of oil, natural gas and NGLs is complex and inexact. The process relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality and reliability of these data can vary. The process also requires a number of economic assumptions, such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, the effect of government regulation, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

•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.

The proved reserve information set forth in this report is based on our prepared estimates. Estimates prepared by others might differ materially from our estimates.

Actual quantities of oil, natural gas and NGL reserves, future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures and operating expenses will most likely vary from our estimates. In addition, the methodologies and evaluation techniques that we use, which include the use of multiple technologies, data sources and interpretation methods, may be different than those used by our competitors. Further, reserve estimates are subject to the evaluator’s criteria and judgment and show important variability, particularly in the early stages of development. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of reserves to reflect

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production history, results of exploration and development activities, prevailing oil, natural gas and NGL prices and other factors, many of which are beyond our control. Our reserves also may be susceptible to drainage by operators on adjacent properties.

You should not assume that the present value of future net cash flows is the current market value of our proved reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on SEC 12-month average pricing, adjusted for market differentials and costs in effect at year-end discounted at 10%. Actual future prices and costs may be materially higher or lower than the prices and costs we used as of the date of an estimate. In addition, actual production rates for future periods may vary significantly from the rates assumed in the calculation.

To maintain and grow our production and cash flows, we must continue to develop existing reserves and locate or acquire new reserves.    Through our drilling programs and the acquisition of properties, we strive to maintain and grow our production and cash flows. However, as we produce from our properties, our reserves decline. Unless we successfully replace the reserves that we produce, the decline in our reserves will eventually result in a decrease in gas and oil production and lower revenues and cash flows from operations. Future natural gas and oil production is, therefore, highly dependent on our success in efficiently finding, developing or acquiring additional reserves that are economically recoverable. We may be unable to find, develop or acquire additional reserves or production at an acceptable cost, if at all. In addition, these activities require substantial capital expenditures.

Lower oil and gas prices and other factors have resulted in ceiling test writedowns in the past and based upon current commodity prices, will result in future ceiling test writedowns or other impairments. We use the full cost method of accounting for our oil and gas producing activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into cost centers that are established on a country-by-country basis. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties. If net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. If required, a ceiling test writedown reduces earnings and stockholders' equity in the period of occurrence. We evaluate the ceiling test quarterly and had our last ceiling test writedown of approximately $1.5 billion ($948 million, after tax) at December 31, 2012. We did not have a ceiling test writedown in 2013 or 2014; however, due to the substantial decline of commodity prices during the fourth quarter of 2014, which has continued so far during the first quarter of 2015, we anticipate that we will have a ceiling test writedown during the first quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes. Subject to these numerous factors and inherent limitations, we believe that an impairment in the first quarter of 2015 could exceed $750 million. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.

The risk that we will be required to further writedown the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase.

Drilling is a high-risk activity.    In addition to the numerous operating risks described in more detail below, the drilling of wells involves the risk that no commercially productive oil or gas reservoirs will be encountered. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. In addition, we are often uncertain of the future cost or timing of drilling, completing and producing wells. Furthermore, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•costs of, or shortages or delays in the availability of, drilling rigs, equipment and materials;
•decreases in oil and gas prices;
•adverse weather conditions and changes in weather patterns;
•unexpected drilling conditions;
•pressure or irregularities in formations;
•surface access restrictions;
•access to, and costs for, water needed in our waterflood project in the GMBU;

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•
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 natural gas, crude oil and related commodities; and
•compliance with, or changes in, environmental, tax and other laws and regulations.

Future drilling activities may not be successful, and if unsuccessful, this could have an adverse effect on our future results of operations and financial condition.

The oil and gas business involves many operating risks that can cause substantial losses.    Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:

•fires and explosions;
•blow-outs and cratering;
•uncontrollable or unknown flows of oil, gas or well fluids;
•formations with abnormal pressures;
•pipe or cement failures and casing collapses;
•pipeline or other facility ruptures and spills;
•equipment malfunctions or operator error;
•adverse weather conditions or natural disasters;
•discharges of toxic gases;
•buildup of naturally occurring radioactive materials;
•vandalism;
•
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.

Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occur, we could incur substantial losses as a result of:

•injury or loss of life;
•severe damage or destruction of property and equipment, and oil and gas reservoirs;
•pollution and other environmental damage;

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•investigatory and clean-up responsibilities;
•regulatory investigation and penalties or lawsuits;
•limitation on or suspension of our operations; and
•repairs to resume operations.

Further, offshore operations are subject to a variety of additional operating risks, such as capsizing, collisions and damage or loss from typhoons or other adverse weather conditions. These conditions could cause substantial damage to facilities and interrupt production. Our China operations are dependent upon the availability, proximity and capacity of gathering systems and processing facilities that we do not own. Necessary infrastructures have been in the past, and may be in the future, temporarily unavailable due to adverse weather conditions or other reasons, or they may not be available to us in the future on acceptable terms or at all.

Failure or loss of equipment, as the result of equipment malfunctions, cyber-attacks or natural disasters, could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Catastrophic occurrences giving rise to litigation, such as a well blowout, explosion or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture could result in extensive environmental pollution and substantial remediation expenses. If our production is interrupted significantly, our efforts at containment are ineffective or litigation arises as the result of a catastrophic occurrence, our cash flows, and in turn, our results of operations, could be materially and adversely affected.

In connection with our operations, we generally require our contractors, which include the contractor, its parent, subsidiaries and affiliate companies, its subcontractors, their agents, employees, directors and officers, to agree to indemnify us for injuries and deaths of their employees, contractors, subcontractors, agents and directors, and any property damage suffered by the contractors. There may be times, however, that we are required to indemnify our contractors for injuries and other losses resulting from the events described above, which indemnification claims could result in substantial losses to us.

While we maintain insurance against some potential losses or liabilities arising from our operations, our insurance does not protect us against all operational risks. The occurrence of any of the foregoing events and any costs or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage or not indemnified, could reduce revenue and the funds available to us for our exploration, exploitation, development and production activities and could, in turn, have a material adverse effect on our business, financial condition and results of operations. See also “- We may not be insured against all of the operating risks to which our business is exposed.”

We are subject to complex laws and regulatory actions that can affect the cost, manner, feasibility or timing of doing business. Existing and potential regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, provincial, tribal, local and international regulation. We may be required to make large expenditures to comply with environmental, habitat and other governmental regulations. Matters subject to regulation include the following, in addition to the other matters discussed under the caption “Regulation” in Items 1 and 2 of this report:

•
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.


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Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource risk mitigation, damages and other environmental or habitat damages. We also could be required to install and operate expensive pollution controls, engage in environmental risk management and derivative activities or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. In addition, failure to comply with applicable laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.

Further, changes to existing environmental regulations or the adoption of new regulations may unfavorably impact us, the oil and gas industry generally, our suppliers or our customers. For example, governments around the world have become increasingly focused on regulating greenhouse gas (GHG) emissions and addressing the impacts of climate change in some manner. In the absence of dedicated federal legislation on climate change mitigation or adaptation, the U.S. Environmental Protection Agency (EPA) has promulgated several rulemakings to regulate, measure or monitor GHG emissions under the existing provisions of the Clean Air Act, or CAA. The EPA has adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, as well as from certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities on an annual basis. The new regulations could impact certain facilities in which we have interests (legal, equitable, operated or non-operated) by increasing regulatory risks and reporting requirements.

In December 2009, the EPA issued an “endangerment finding” under the CAA concluding that the current and projected concentrations of GHGs in the atmosphere from motor vehicles threaten the public health and welfare of current and future generations. The finding, once made, required the EPA to begin regulating GHG emissions from new cars and light trucks under the CAA. Indirectly, the EPA argued that it also triggered an EPA obligation to regulate GHG emissions under existing relevant air permitting programs for large stationary sources. On January 2, 2011, the EPA initiated Prevention of Significant Deterioration (PSD) permitting requirements for carbon dioxide and other GHGs from large and modified stationary sources. Permits limiting GHGs have been issued for a variety of new or modified facilities under the Clean Air Act PSD program. GHG emissions also trigger Title V operating permit requirements for new and existing sources that exceed certain established emission thresholds. Emission levels in excess of these thresholds can then trigger preconstruction permit requirements and application of best available control technology (BACT) or operation consistent with the lowest achievable emissions rate (LAER) as determined on a source-by-source basis.

In June 2014, the Supreme Court upheld most of the EPA’s GHG permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the Clean Air Act’s prevention of significant deterioration (PSD) and Title V requirements. Certain of our equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, also be subject to the installation of controls to capture GHGs. For any equipment or installation so subject, we may have to incur increased compliance costs to capture GHGs.

The EPA took additional action under the Clean Air Act in June 2014. In accordance with the President of the United States' Climate Action Plan, on June 18, 2014, the EPA proposed rules to reduce carbon emissions from electric generating units. The proposal, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units, commencing in 2020, with the reductions to be fully phased in by 2030. Under the proposal, each state would be given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 30% from 2005 levels. 

As proposed, states are given great flexibility in meeting their emission reduction targets, and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units, renewable or end-use energy efficiency. It is not possible at this time to predict what requirements might be adopted by the EPA in the final rule, expected in 2015, or how any such final rule would impact our business. 

Recently, the President of the United States announced that the EPA would propose by mid-2015, a new series of regulations to reduce methane emissions from the oil and gas industry by 2025 by about 40 to 45% from 2012 levels. These rules are in addition to a series of recent EPA oil and gas rules designed to curb volatile organic compound (VOC) emissions from natural gas wells and related equipment, such as storage vessels and glycol dehydrators.

If the U.S. Congress adopts market-based tax, energy or other mechanisms to regulate the carbon intensity of natural resources, or promote or require the reduction of GHG emissions from certain industrial sectors, such legislation, depending on design and scope, could increase the cost of oil and gas production and market demand. Some states, like California, have implemented state-wide GHG mitigation programs to reduce GHG emissions through a mixture of regulatory programs,

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including a low carbon fuel standard and cap-and-trade market applicable to, among others, electric utilities and transportation fuels.

Further, the U.S. Congress has previously proposed legislation that would directly impact our industry. In response to the 2010 Macondo incident in the Gulf of Mexico, the U.S. Congress considered a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.

Some federal agencies are adopting new rules governing hydraulic fracturing on leased federal or tribal trust lands. Meanwhile, states, tribes and municipalities across the country have issued moratoria banning hydraulic fracturing. While we cannot predict how these rules will impact our business, they will likely increase costs or otherwise limit where we may conduct exploration and production activities.

In December 2014, the Council on Environmental Quality issued draft guidance on consideration of climate change in project reviews under the National Environmental Policy Act (NEPA). We do not know whether and when this guidance may become final, nor can we predict its likely impact on our business. It is possible, however, that closer consideration of climate change may require BLM or other federal agencies to require enhanced environmental protections, at increased costs to operations like ours, at hydraulic fracturing sites across the country.

These and other potential legislative proposals, along with any applicable legislation introduced and passed in Congress, could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows. See also “- The potential adoption of federal, state, tribal and local legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.”

Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Additional costs or operating restrictions associated with legislation or regulations could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.

The potential adoption of federal, state, tribal and local legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on almost all of our U.S. onshore oil and natural gas properties. Hydraulic fracturing involves using water, sand or other proppant materials, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore.

As explained in more detail below, the hydraulic fracturing process is typically regulated by state oil and natural gas agencies, although the EPA, the BLM and other federal regulatory agencies have taken steps to review or impose federal regulatory requirements. Certain states in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Certain municipalities have already banned hydraulic fracturing, and courts have upheld those moratoria in some instances. In the past several years, dozens of states have approved or considered additional legislative mandates or administrative rules on hydraulic fracturing.

For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process, and the RCT promulgated rules regarding the same in December 2011. On September 11, 2012, the RCT approved new regulations relating to the commercial recycling of produced water and/or hydraulic-fracturing flowback fluid. In addition, in May 2013 the RCT adopted amendments to Statewide Rule 13 governing casing, cementing, well control and completion of oil and gas wells; these new construction requirements took effect on January 1, 2014.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. For example, on June 30, 2014, New York’s highest state court upheld local zoning ordinances that ban hydraulic fracturing within municipal limits.


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In the event state, local or municipal legal restrictions are adopted in areas where we are currently conducting operations, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Depending on the areas in which they are adopted, such restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

In addition, on July 3, 2014, major university and U.S. Geological Survey researchers published a study purporting to find a causal connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008. This study may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, our operations may be curtailed while alternative treatment and disposal methods are developed and approved.

The EPA is also developing a proposed rule to amend the Effluent Limitations Guidelines for the Oil and Gas Extraction Category. The proposed rule is scheduled for publication in 2015. It is unclear what the proposed rule will require, but with potential future limits on deep well injection, these limits may become increasingly important, as extraction and production companies look to dispose of wastewater to publicly-owned treatment works or centralized waste treaters. If deep well injection is shut down or limited, and discharge to surface waters is impossible, we may face increased disposal costs.
 
In recent years, the federal government has increased its focus on the environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality has coordinated an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices involving the use of diesel fuel.

The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuels under the Safe Drinking Water Act and in February 2014 issued permitting guidance for hydraulic fracturing activities using diesel.

Further, on May 19, 2014, the EPA published an Advance Notice of Proposed Rulemaking (ANPR) under the Toxic Substances Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production. Depending on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and failure to do so may subject us to penalties.

In addition, in May 2013, the Bureau of Land Management issued a proposed rule that would require the public disclosure of chemicals used in hydraulic fracturing operations, set requirements for well-bore integrity and establish flowback water standards for all hydraulic fracturing operations on federal public lands and American Indian Tribal lands. The proposed rule also required that an operator certify, in writing, that (a) the stimulation design complies with all federal, state, tribal and local regulations; (b) the stimulation was completed in accordance with the design approved by BLM and all applicable regulations; and (c) the well-bore integrity was maintained during the fracturing process and flowback water was properly stored, treated and disposed. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with draft results to be issued in 2015 for public comment and peer review.

In addition, the U.S. Department of Energy has conducted an investigation into practices to better protect the environment from drilling using hydraulic fracturing completion methods. In a November 18, 2011 report, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued 20 recommendations to federal agencies, states and private entities that are intended to reduce the environmental impact and assure the safety of shale gas production. The U.S. Department of Energy continues to work with other federal agencies to identify best practices for shale gas production. Some of these may become enforceable statutory or regulatory requirements that would likely increase our compliance costs.

Given the heightened awareness regarding the use of hydraulic fracturing, it is possible that regulatory agencies or private parties may suggest that hydraulic fracturing has caused groundwater or surface water contamination, whether or not such allegations are accurate. For example, on December 8, 2011, the EPA released a preliminary report indicating that hydraulic fracturing is responsible for groundwater contamination in Pavillion, Wyoming, although the EPA’s draft report has been vigorously criticized as ignoring certain facts and utilizing incorrect data. In addition, the EPA alleged in an enforcement action against an operator in Texas that the operator contaminated local groundwater wells, although the RCT found after an evidentiary hearing that the operator was not responsible for the contamination. However, in 2013 the EPA deferred the Pavillion matter to state oversight and withdrew the emergency action order in Texas. Nevertheless, energy extraction, with a focus on onshore natural gas production, remains an EPA enforcement initiative. Thus, regulatory agencies or private parties

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alleging groundwater contamination linked to hydraulic fracturing could trigger defense costs in administrative or civil litigation or proceedings to rebut the allegations.

Additionally, certain members of the Congress have called upon (a) the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, (b) the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and (c) the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

Further, on August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA finalized rules under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. The EPA regulations include NSPS standards for completions of hydraulically-fractured gas wells.
Since January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAPS include specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. EPA has revised this rule two times, in September 2013 and December 2014. We have and continue to evaluate the effect of these regulations, including the latest revisions, on our business. Compliance with such regulations could result in additional costs, including increased capital expenditures and operating costs, for us and our customers which may adversely impact our business.

Based on the foregoing, increased regulation and attention given to the hydraulic fracturing process from federal agencies, various states and local governments could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

We could be adversely affected by the credit risk of financial institutions.    We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds and other institutions. In the event of default of a counterparty, we would be exposed to credit risks. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative contracts and insurance companies in the form of claims under our policies. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

Our use of oil and natural gas price derivative contracts may limit future revenues from price increases and involves the risk that our counterparties may be unable to satisfy their obligations to us.    As part of our risk management program, we generally use derivative contracts to protect a substantial, but varying, portion of our anticipated future oil and gas production for the next 24-36 months to reduce our exposure to fluctuations in oil and natural gas prices. As of December 31, 2014, we had no outstanding derivative contracts related to our NGL production. A significant portion of our crude oil derivative contracts include short puts. If market prices remain below our sold puts at contract settlement, we will receive the difference between our floors or swaps and the associated sold puts, effectively limiting the downside protection of these contracts. In the case of acquisitions, we may use derivative contracts to protect acquired production from commodity price volatility for a longer period. In addition, we may utilize basis contracts to hedge the differential between the relevant underlying commodity reference prices and those of our physical pricing points. While the use of derivative contracts may limit or reduce the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements and expose us to the risk of financial loss in certain circumstances. Those circumstances include instances where our production is less than the volume subject to derivative contracts or there is a widening of price basis differentials between delivery points for our production and the delivery points assumed in the derivative transactions.

The use of derivative transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to perform their financial and other obligations under such transactions. If any of our counterparties were to default on its obligations to us under the derivative contracts, enter receivership or seek bankruptcy or similar protection, that could

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result in an economic loss to us and could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened, and it is possible that fewer counterparties will participate in future derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes.

Federal legislation regarding swaps could adversely affect the costs of, or our ability to enter into, those transactions.    Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which was passed by Congress and signed into law in July 2010, amends the Commodity Exchange Act (CEA) to establish a comprehensive new regulatory framework for over-the-counter derivatives, or swaps, and swaps market participants, such as Newfield. The Dodd-Frank Act requires certain swaps to be cleared through a derivatives clearing organization, unless an exception from mandatory clearing is available, and if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility, and that market participants post margin for uncleared swaps. The CEA provides that non-financial entity end-users, such as Newfield, that enter into swaps to hedge or mitigate commercial risk may elect an exception from the mandatory clearing and exchange trading requirements. However, unless an exemption from the Dodd-Frank Act’s margin requirements is available, our derivative transactions could be subject to higher costs due to margin payments to swap counterparties. While we do not expect that we will be required to post margin for uncleared swaps, the Commodity Futures Trading Commission (CFTC) has not yet finalized the margin rules. Therefore, we are unable to determine the future costs on our derivative activities at this time.

Higher costs associated with the Dodd-Frank Act can create disincentives for end-users like Newfield to hedge their commercial risks, including market price fluctuations associated with anticipated production of oil and gas. The Dodd-Frank Act and related rules and regulations promulgated by CFTC could potentially increase the cost of Newfield’s risk management activities, which could adversely affect our available liquidity, materially alter the terms of our swap contracts, reduce the availability of swaps to hedge or mitigate risks we encounter, reduce our ability to monetize or restructure existing swap contracts, and increase our regulatory compliance costs related to our swap activities. In addition, if we reduce our use of swaps, our results of operations and cash flows may be adversely affected, including by becoming more volatile and less predictable, which also could adversely affect our ability to plan for and fund capital expenditures. It is also possible that the Dodd-Frank Act and related rules and regulations could affect prices for commodities that we purchase, use or sell, which, in turn, could adversely affect our liquidity or financial condition.

In December 2013, the CFTC re-proposed rules to amend the CEA to establish position limits for certain commodity futures and options contracts, and physical commodity swaps that are economically equivalent to such contracts, including on commodity derivative transactions in which we engage in beyond certain thresholds. If the CFTC position limit regulations are ultimately adopted substantially in the form proposed, they could result in additional compliance costs and alter our ability to effectively manage our commercial risks. Until the CFTC adopts final rules with respect to position limits and any exemptions for bona fide derivative transactions or off-setting positions from those limits, we will be unable to determine whether the CFTC’s proposed rules could result in additional derivative costs or adversely affect our ability to effectively manage our commercial risks.

Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on the leases or units containing the leasehold acreage.   Leases on oil and gas properties normally have a term of three to five years and will expire unless, prior to expiration of the lease term, production in paying quantities is established. If the leases expire and we are unable to renew them, we will lose the right to develop the related properties. The risk of the foregoing increases in periods of sustained low commodity prices due to the corresponding impact on our drilling plans and the likely decrease in what is considered economic production under the leases. Our drilling plans for these areas are subject to change based upon various factors, including commodity prices, drilling results, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.    In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:

•the repeal of the percentage depletion allowance for oil and gas properties;
•the elimination of current deductions for intangible drilling and development costs;

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•the elimination of the deduction for certain U.S. production activities; and
•an extension of the amortization period for certain geological and geophysical expenditures.

These proposals were also included in the President of the United States' Proposed Fiscal Year 2014 Budget. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of such legislation or any other similar changes in U.S. Federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.    The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. We deliver oil and gas through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through some firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical or other reasons, or may not be available to us in the future at a price that is acceptable to us. New regulations on the transportation of crude oil by rail, like those issued via emergency orders by the U.S. Department of Transportation (DOT) in 2014, may increase our transportation costs. In addition, federal and state regulation of natural gas and oil production, processing and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints and general economic conditions could adversely affect our ability to produce, gather and transport natural gas. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition, results of operations and cash flows.

We have risks associated with our China operations.    Ownership of property interests and production operations in China are subject to the various risks inherent in international operations. These risks may include:

•currency restrictions and exchange rate fluctuations;
•
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;
•increases in taxes and governmental royalties;
•
transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act and other anti-corruption compliance laws and issues;
•disruptions in international crude 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.


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Our China operations also may be adversely affected by the laws and policies of the United States affecting foreign trade, taxation, investment and transparency issues. In addition, if a dispute arises with respect to our China operations, we may be subject to the exclusive jurisdiction of non-U.S. courts or may not be successful in subjecting non-U.S. persons to the jurisdiction of the courts of the United States. Realization of any of the factors listed above could materially and adversely affect our financial position, results of operations or cash flows.

Material differences between the estimated and actual timing of critical events may affect the completion of and commencement of production from our Pearl development project in China. Our Pearl facility in the South China Sea is a large, offshore development project. The completion of our drilling in this project may be delayed beyond our anticipated completion dates. Key factors that may affect the timing and outcome of this project include the following:
•project approvals by our joint-venture partner(s);
•timely issuance of permits and licenses by governmental agencies or legislative and other governmental approvals;
•weather conditions;
•availability of personnel;
•civil and political environment in China; and
•manufacturing and delivery schedules of critical equipment.
Delays and differences between estimated and actual timing of critical events may affect the forward-looking statements related to our Pearl development and could have a material adverse effect on our expected timing and amount of cash flows from China and international results of operations.

Competition for, or the loss of, our senior management or experienced technical personnel may negatively impact our operations or financial results. To a large extent, we depend on the services of our senior management and technical personnel and the loss of any key personnel could have a material adverse effect on our business, financial condition and operating results. Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain a seasoned management team and experienced explorationists, engineers, geologists and other professionals. Competition for these professionals remains strong. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. We are likely to continue to experience increased costs to attract and retain these professionals.

Competition in the oil and gas industry is intense. We operate in a highly competitive environment for acquiring properties and marketing oil, natural gas and NGLs. Our competitors include multinational oil and gas companies, major oil and gas companies, independent oil and gas companies, individual producers, financial buyers as well as participants in other industries supplying energy and fuel to consumers. Many of our competitors have greater and more diverse resources than we do. In addition, high commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop and operate properties. Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek new entry. As a consequence, our competitors may be able to address these competitive factors more effectively than we can. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.

Shortages of oilfield equipment, services, supplies and qualified field personnel could adversely affect financial condition and results of operations. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for that equipment has increased along with the number of wells being drilled. The demand for qualified and experienced field personnel to drill wells and conduct field operations can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These factors have caused significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment, services and raw materials. Similarly, lower crude oil and natural gas prices generally result in a decline in service costs due to reduced demand for drilling and completion services. If the current market changes, and commodity prices quickly recover, we may face shortages of field personnel, drilling rigs, or other equipment or supplies, which could delay or adversely affect our exploration and development operations and have a material adverse effect on our business, financial condition, results of operations or cash flows, or restrict operations.


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Our ability to produce oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner. Development activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of natural gas and oil from many reservoirs requires the use and disposal of significant quantities of water in addition to the water we use to develop our waterflood in the GMBU. In certain regions, there may be insufficient local capacity to provide a source of water for drilling activities. In these cases, water must be obtained from other sources and transported to the drilling site, adding to the operating cost. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations, such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of natural gas and oil. In recent history, public concern surrounding increased seismicity has heightened focus on our industry's use of water in operations, which may cause increased costs, regulations or environmental initiatives impacting our use or disposal of water.

We may not be insured against all of the operating risks to which our business is exposed. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, such as well blowouts, explosions, oil spills, releases of gas or well fluids, fires, pollution and adverse weather conditions, which could result in substantial losses to us. See also “- The oil and gas business involves many operating risks that can cause substantial losses.” Exploration and production activities are also subject to risk from political developments such as terrorist acts, piracy, civil disturbances, war, expropriation or nationalization of assets, which can cause loss of or damage to our property. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our insurance coverage will adequately protect us against liability from all potential consequences, damages and losses.

We currently have insurance policies covering our onshore and offshore operations that include coverage for general liability, excess liability, physical damage to our oil and gas properties, operational control of wells, oil pollution, third-party liability, workers’ compensation and employers’ liability and other coverages. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution and other environmental issues, with broader coverage for sudden and accidental occurrences. For example, we maintain operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that we may incur from a sudden incident that results in negative environmental effects, including obligations, expenses or claims related to seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the specific event of a well blowout or out-of-control well resulting in negative environmental effects, such operators extra expense coverage would be our primary source of coverage, with the general liability and excess liability coverage referenced above also providing certain coverage.

In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay claims.

Further, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. If we incur substantial liability from a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower revenues and funds available to us for our operations, that could, in turn, have a material adverse effect on our business, financial condition and results of operations.

We may be subject to risks in connection with acquisitions and divestitures.    As part of our business strategy, we have made and will likely continue to make acquisitions of properties and to divest non-strategic assets. Suitable acquisition properties or suitable buyers of our non-strategic assets may not be available on terms and conditions we find acceptable.

Acquisitions pose substantial risks to our business, financial condition and results of operations. These risks include that the acquired properties may not produce revenues, reserves, earnings or cash flows at anticipated levels. Also, the integration of properties we acquire could be difficult. In pursuing acquisitions, we compete with other companies, many of which have

35

greater financial and other resources to acquire properties. The successful acquisition of producing properties requires an assessment of several factors, including:

•recoverable reserves;
•exploration potential;
•future oil and gas prices and their appropriate differentials;
•operating costs and production taxes; and
•potential environmental and other liabilities.

These assessments are complex and the accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

In addition, our divestitures may pose residual risks to the Company, such as divestitures where we retain certain liabilities or we have legal successor liability due to the bankruptcy or dissolution of the purchaser. Uneconomic or unsuccessful acquisitions and divestitures may divert management’s attention and financial resources away from our existing operations, which could have a material adverse effect on our financial condition.

We depend on computer and telecommunications systems, and failures in our systems or cyber security attacks could significantly disrupt our business operations.    The oil and gas industry has become increasingly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our business partners, including vendors, service providers, purchasers of our production and financial institutions, are also dependent on digital technology. It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any cyber incidents or interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could lead to data corruption, communication interruption, unauthorized release, gathering, monitoring, misuse or destruction of proprietary or other information, or otherwise significantly disrupt our business operations. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

We are exposed to counterparty credit risk as a result of our receivables.    We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas and NGLs to a variety of purchasers. Some of our purchasers and non-operating partners may experience credit downgrades or liquidity problems and may not be able to meet their financial obligations to us. Nonperformance by a trade creditor or non-operating partner could result in financial losses.

Hurricanes, typhoons, tornadoes, earthquakes and other natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flow.    Hurricanes, typhoons, tornadoes, earthquakes and other natural disasters can potentially destroy thousands of business structures and homes and, if occurring in the Gulf Coast region of the United States, could disrupt the supply chain for oil and gas products. Disruptions in supply could have a material adverse effect on our business, financial condition, results of operations and cash flow. Damages and higher prices caused by hurricanes, typhoons, tornadoes, earthquakes and other natural disasters could also have an adverse effect on our financial condition due to the impact on the financial condition of our customers.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital. We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, and commodity pricing levels are also considered by the rating agencies. A ratings downgrade could

36

adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit or other forms of collateral for certain obligations.

Our level of indebtedness and the restrictive covenants in the agreements governing our indebtedness and other financial obligations may reduce our operating flexibility.    As of December 31, 2014, we had total indebtedness of $2.9 billion, including $0.4 billion in borrowings under our revolving credit facility and money market lines of credit. The indenture governing our outstanding notes and the agreements governing our other indebtedness and financial obligations contain, and any indenture that will govern other debt securities issued by us may contain, various covenants that limit our ability and the ability of specified subsidiaries of ours to, among other things:

•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.

These restrictions and our level of indebtedness could limit our ability to:

•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.

Some of the agreements governing our indebtedness and other financial obligations also require the maintenance of specified financial ratios and the satisfaction of other financial conditions. Our ability to meet those financial ratios and conditions, and to comply with other covenants and restrictions in our financing agreements, can be affected by unexpected downturns in business operations beyond our control, such as a volatile energy commodity cost environment or an economic downturn. Accordingly, we may be unable to meet these obligations. This failure could impair our operating capacity and cash flows and could restrict our ability to incur debt or to make cash distributions, even if sufficient funds were available.

Our breach of any of these covenants could result in a default under the terms of the relevant indebtedness, which could cause such indebtedness or other financial obligations to become immediately due and payable. If the lenders accelerate the repayment of borrowings or other amounts owed, we may not have sufficient assets to repay our indebtedness or other financial obligations, including our outstanding notes and any future debt securities. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, or repay such debt with the proceeds from a sale of assets or a public offering of securities. Factors that will affect our ability to successfully complete a public offering, refinance our debt or conduct an asset sale include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure that we will be able to generate sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations.

Our certificate of incorporation, bylaws, some of our arrangements with employees and Delaware law contain provisions that could discourage an acquisition or change of control of our Company.    Our certificate of incorporation and

37

bylaws contain provisions that may make it more difficult to affect a change of control of our Company, to acquire us or to replace incumbent management. In addition, our change of control severance plan and agreements and our omnibus stock plans contain provisions that provide for severance payments and accelerated vesting of benefits, including accelerated vesting of restricted stock, restricted stock units and stock options, upon a change of control. Section 203 of the Delaware General Corporation Law also imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. These provisions could discourage or prevent a change of control, even if it may be beneficial to our stockholders, or could reduce the price our stockholders receive in an acquisition of our Company.

38


Item 1B. Unresolved Staff Comments

Not applicable.
 
Item 3. Legal Proceedings

Between February and December 2013, we voluntarily self-disclosed to the U.S. Environmental Protection Agency (EPA) certain potential federal air quality violations at our facilities located on state lands and on the Uintah and Ouray Indian Reservation in the Uinta Basin of northeast Utah. The self-disclosures were made after a voluntary internal environmental audit under the EPA's Self-Disclosure and Audit Policy. The potential violations related primarily to certain stationary internal combustion engines that are subject to certain air quality performance standards under 40 C.F.R. Part 60, Subpart JJJJ. The engines were installed as a result of our efforts to replace older, higher-emitting engines with new, lower-emitting engines. Subpart JJJJ requires us to conduct certain emission performance tests within a defined time period. We did not conduct all of the requisite tests on the new engines in a timely fashion and have now negotiated a settlement and resolution with the EPA by entering in to a Combined Complaint and Consent Agreement and Compliance Order on Consent. Those settlement documents require us to pay a monetary penalty of $246,000 and conduct testing for numerous engines. The settlement documentation was finalized on October 20, 2014 and the penalty was paid timely on November 7, 2014. The required performance testing is ongoing and we anticipate that work to be completed in a timely manner, consistent with the requirements of the settlement. The violations did not contain any allegations of environmental spills, releases or pollution above permitted levels. We do not expect this matter to have a material adverse effect on our financial position, cash flows or results of operations.

In early 2012, through a voluntary environmental audit, we discovered potential violations of section 404 of the Clean Water Act relating to possible unpermitted discharges of fill materials into certain wetlands and drainages in the Uinta Basin. The potential violations were discovered on certain Newfield locations and several locations acquired in 2011. In June 2012, we self-disclosed these potential violations to the U.S. Army Corps of Engineers (Corps), in accordance with the EPA’s Audit Policy and an interagency memorandum of understanding with the Corps. The Corps initially indicated to us that it would not pursue penalty charges, but instead would work with us to restore the unpermitted discharges and acquire the appropriate after-the-fact permits. The EPA later inquired with the Corps, and was informed about the potential violations. Thereafter, the EPA initiated an administrative enforcement action against Newfield. The EPA has evaluated the discharges and our proposed restoration and mitigation, and a negotiated settlement has been finalized. On November 13, 2014, Newfield entered into an Administrative Order on Consent and a Combined Complaint and Consent Agreement to settle the matter. The EPA executed both agreements on December 17, 2014. The EPA published the notice of the Combined Complaint and Consent Agreement on December 17, 2014, for a 40-day comment period. No comments were received by the EPA. The settlement terms involved payment of a $175,000 penalty, restoration of much of the unpermitted discharges and off-site mitigation. The EPA issued the Final Order together with the fully executed Combined Complaint and Consent Agreement on January 27, 2015. The penalty will be paid before February 27, 2015 and the remediation and mitigation work will begin in 2015. We do not expect this administrative settlement to have a material adverse effect on our financial position, cash flows or results of operations. 

We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations. In addition, from time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate related to alleged violations of environmental statutes or rules and regulations promulgated thereunder. We cannot predict with certainty whether these notices of violation will result in fines or penalties, or if such fines or penalties are imposed, that they would individually or in the aggregate exceed $100,000. If any fines or penalties are in fact imposed that are greater than $100,000, then we will disclose such fact in our subsequent filings.
 
Item 4.
Mine Safety Disclosures

Not applicable.

39

Executive Officers of the Registrant

The following table sets forth the names, ages (as of February 20, 2015) and positions held by our executive officers. Our executive officers serve at the discretion of our Board of Directors. 
Name
 
Age
 
Position
 
Total Years of Service with Newfield
Lee K. Boothby
 
53
 
President, Chief Executive Officer and Chairman of the Board
 
15
Lawrence S. Massaro
 
51
 
Executive Vice President and Chief Financial Officer
 
4
Gary D. Packer
 
52
 
Executive Vice President and Chief Operating Officer
 
19
George T. Dunn
 
57
 
Senior Vice President — Development
 
22
John H. Jasek
 
45
 
Senior Vice President — Operations
 
15
Stephen C. Campbell
 
46
 
Vice President — Investor Relations
 
15
George W. Fairchild, Jr.
 
47
 
Chief Accounting Officer and Assistant Corporate Secretary
 
3
John D. Marziotti
 
51
 
General Counsel and Corporate Secretary
 
11
Valerie A. Mitchell
 
43
 
Vice President — Mid-Continent
 
10
Matthew R. Vezza
 
41
 
Vice President — Rocky Mountains
 
2

Lee K. Boothby was named Chairman of the Board of Directors in May 2010, Chief Executive Officer in May 2009 and President in February 2009. Prior to this, he was Senior Vice President — Acquisitions and Business Development. From 2002 to 2007, he was Vice President — Mid-Continent. From 1999 to 2001, Mr. Boothby was Vice President and Managing Director — Newfield Exploration Australia Ltd. and managed operations in the Timor Sea (divested in 2003) from Perth, Australia. Prior to joining Newfield in 1999, Mr. Boothby worked for Cockrell Oil Corporation, British Gas and Tenneco Oil Company. He serves as a board member for America’s Natural Gas Alliance and the American Exploration and Production Council. He is a member of the Louisiana State University Craft & Hawkins Department of Petroleum Engineering Advisory Committee, the Society of Petroleum Engineers, the Independent Petroleum Association of America and the Rice University Jones Graduate School of Business Council of Overseers. He holds a degree in Petroleum Engineering from Louisiana State University and a Master of Business Administration from Rice University.

Lawrence S. Massaro was promoted to Executive Vice President and Chief Financial Officer in November 2013. Mr. Massaro joined Newfield in March 2011 and served as Vice President — Corporate Development until November 2013. In this position, he led the Company's business development, strategic planning and product marketing efforts. Prior to joining Newfield, Mr. Massaro served as Managing Director at JP Morgan in its oil and gas investment banking group beginning in 2005 and was Vice President, Corporate Strategy and Business Development while at Amerada Hess Corporation from 1995 to 2005. He also held various senior petroleum engineering positions at both PG&E Resources from 1992 to 1994 and at British Petroleum from 1985 to 1991. Mr. Massaro holds a degree in Petroleum Engineering from Texas A&M University and a Master of Business Administration from Southern Methodist University.

Gary D. Packer was promoted to the position of Executive Vice President and Chief Operating Officer in May 2009. Prior thereto, he was promoted from Gulf of Mexico General Manager to Vice President — Rocky Mountains in November 2004. Mr. Packer joined the Company in 1995. Prior to joining Newfield, Mr. Packer worked for Amerada Hess Corporation in both the Rocky Mountains and Gulf of Mexico divisions. Prior to these roles, he worked for Tenneco Oil Company. In December 2014, Mr. Packer joined the board of directors of Bennu Oil & Gas, LLC, a private oil and gas company operating offshore in the Gulf of Mexico. He serves as a board member for the Independent Petroleum Association of America (IPAA). He holds a degree in Petroleum and Natural Gas Engineering from Penn State University.

George T. Dunn was promoted to Senior Vice President — Development in September 2012, previously serving as Vice President — Mid-Continent beginning in October 2007. He managed our onshore Gulf Coast operations from 2001 to October 2007, and was promoted from General Manager to Vice President in November 2004. Before managing our Gulf Coast operations, Mr. Dunn was the General Manager of our Western Gulf of Mexico division. Prior to joining Newfield in 1992, Mr. Dunn was employed by Meridian Oil Company and Tenneco Oil Company. He holds a degree in Petroleum Engineering from the Colorado School of Mines.




40

John H. Jasek was promoted to Senior Vice President — Operations in October of 2014, after serving as Vice President — Onshore Gulf Coast since February 2011. Prior to that, Mr. Jasek served as Vice President — Gulf of Mexico from December 2008 until February 2011 and as Vice President — Gulf Coast from October 2007 until December 2008 while also serving as the manager of our onshore Gulf Coast operations. He previously managed our Gulf of Mexico operations from March 2005 until October 2007, and was promoted from General Manager to Vice President in November 2006. Prior to March 2005, he was a Petroleum Engineer in the Western Gulf of Mexico. Before joining Newfield, Mr. Jasek worked for Anadarko Petroleum Corporation and Amoco Production Company. He has a degree in Petroleum Engineering from Texas A&M University.

Stephen C. Campbell was promoted to Vice President — Investor Relations in December 2005, after serving as Newfield’s Manager — Investor Relations since 1999. Prior to joining Newfield, Mr. Campbell was the Investor Relations Manager at Anadarko Petroleum Corporation from 1993 to 1999 and the Assistant Vice President of Marketing & Communications at United Way, Texas Gulf Coast from 1990 to 1993. He is a member of the National Investor Relations Institute. He holds a Bachelor of Science degree in Journalism from Texas A&M University.

George W. Fairchild, Jr. was promoted to Chief Accounting Officer and Assistant Corporate Secretary in November 2013. Mr. Fairchild joined Newfield in August of 2012 as Controller and Assistant Corporate Secretary and has served as the Company’s Principal Accounting Officer since joining the Company. Prior to joining Newfield, Mr. Fairchild served as Controller for Sheridan Production Company LLC, a privately-held oil and gas company, beginning in 2009 and was Vice President and Controller of Davis Petroleum Corporation, also a privately-held oil and gas company, from 2006 to 2009. Prior thereto, Mr. Fairchild was with Burlington Resources Inc., a publicly-held oil and gas company, serving as Senior Manager — Accounting Policy & Research from 2001 to 2006 and Manager — Internal Audit from 2000 to 2001. Before joining Burlington Resources Inc., he was with PricewaterhouseCoopers LLP from 1993 to 2000. Mr. Fairchild served in the U.S. Air Force from 1986 to 1990. He holds a Bachelor of Business Administration in Accounting from the University of Texas at Austin and is a Certified Public Accountant in the state of Texas.

John D. Marziotti was promoted to General Counsel in August 2007 and was named Corporate Secretary in May 2008. Prior to joining Newfield in 2003, Mr. Marziotti was a partner at the law firm of Strasburger & Price, LLP in their Houston office. He received his Juris Doctor degree from Southern Methodist University and a Bachelor of Arts degree from the College of Charleston and is a member of the State Bar of Texas, the Houston Bar Association, the Association of Corporate Counsel, Texas General Counsel Forum and is a Board Leadership Fellow with the National Association of Corporate Directors.

Valerie A. Mitchell was promoted to Vice President — Mid-Continent effective February 9, 2015, after serving as Vice President — Corporate Development beginning in June of 2014. From 2011 to June 2014, she served as General Manager of our Mid-Continent business unit. Prior to that, Ms. Mitchell served in a number of leadership roles since joining Newfield in July 2004, including business development manager for our onshore Gulf Coast region and asset lead and asset manager from 2009 to 2011. Ms. Mitchell began her career as a reservoir engineer with Shell Oil in 1996 and thereafter worked in various technical and management positions at Coastal and El Paso. She has served in leadership positions for several industry organizations including the Oklahoma Independent Producers Association and the Society of Petroleum Engineers. She holds a Bachelor of Science in Chemical Engineering from the University of Missouri-Columbia.

Matthew R. Vezza was promoted to Vice President — Rocky Mountains in June of 2014. Mr. Vezza joined Newfield in August 2012 as General Manager of our Rocky Mountains business unit after 16 years with Marathon Oil Company. Mr. Vezza began his career at Marathon in 1996 as a production engineer and then moved through the organization in various technical and managerial roles in Oklahoma, Texas, Louisiana, Colorado and Wyoming. While at Marathon, Mr. Vezza's last position, from August 2009 to August 2012, was serving as Asset Manager - Wyoming. Mr. Vezza is a member of the Society of Petroleum Engineers and holds a Bachelor of Science in Petroleum and Natural Gas Engineering from Penn State University.





41

PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for Common Stock

Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol “NFX.” The following table sets forth, for each of the periods indicated, the high and low reported sales price of our common stock on the NYSE. 
 
 
High
 
Low
2013:
 
 
 
 
First Quarter
 
$
30.50

 
$
22.14

Second Quarter
 
25.73

 
19.57

Third Quarter
 
28.41

 
22.71

Fourth Quarter
 
32.55

 
22.79

2014:
 
 
 
 
First Quarter
 
$
31.75

 
$
23.57

Second Quarter
 
44.26

 
30.94

Third Quarter
 
45.43

 
36.97

Fourth Quarter
 
37.49

 
22.90

2015:
 
 
 
 
First Quarter (through February 20, 2015)
 
$
33.46

 
$
22.31


On February 20, 2015, the last reported sales price of our common stock on the NYSE was $32.09. As of that date, there were approximately 1,526 holders of our common stock.

Dividends

We have not paid any cash dividends on our common stock and do not intend to do so in the foreseeable future. We intend to retain earnings for the future operation and development of our business. Any future cash dividends to holders of our common stock would depend on future earnings, capital requirements, our financial condition and other factors determined by our Board of Directors. The covenants contained in our credit facility and in the indentures governing our 6⅞% Senior Subordinated Notes due 2020, our 5¾% Senior Notes due 2022 and our 5⅝% Senior Notes due 2024 could restrict our ability to pay cash dividends. See “Contractual Obligations” under Item 7 of this report and Note 9, “Debt,” to our consolidated financial statements in Item 8 of this report.

Issuer Purchases of Equity Securities

The following table sets forth certain information with respect to repurchases of our common stock during the three months ended December 31, 2014. 
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, 2014
 
7,763

 
$
36.81

 
—
 
—
November 1 — November 30, 2014
 
6,650

 
31.69

 
—
 
—
December 1 — December 31, 2014
 
3,672

 
25.53

 
—
 
—
Total
 
18,085

 
$
32.64

 
—
 
—
 _________________
(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.

42

Stockholder Return Performance Presentation

The performance presentation below is being furnished pursuant to applicable rules of the SEC. As required by these rules, the performance graph was prepared based upon the following assumptions:

•
$100 was invested in our common stock, the S&P 500 Index, the Philadelphia Oil/Exploration & Production Index (EPX) and our peer group on December 31, 2009 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.

For 2015, we refreshed our peer group to better reflect our focus on U.S. domestic resource plays.

New Peer Group.    Our new peer group consists of Cimarex Energy Co., Continental Resources Inc., EP Energy Corp., QEP Resources Inc., SandRidge Energy Inc., SM Energy Company and Whiting Petroleum Corporation.

Prior Peer Group.    Our prior peer group consisted of Bill Barrett Corp., Carrizo Oil & Gas Inc., EP Energy Corp., Halcon Resources Corp., QEP Resources Inc., Rosetta Resources Inc., SandRidge Energy Inc. and SM Energy Company.

Comparison of Five-Year Cumulative Total Return


Total Return Analysis
12/31/2009

12/31/2010

12/31/2011

12/31/2012

12/31/2013

12/31/2014

Newfield Exploration Company
$
100.00

$
149.51

$
78.23

$
55.53

$
51.07

$
56.23

S&P 500 Index - Total Returns
100.00

115.06

117.49

136.30

180.44

205.14

PHLX SIG Oil Exploration & Production Index
100.00

123.12

111.96

104.20

131.89

94.56

New Peer Group
100.00

147.15

138.23

132.96

190.89

128.28

Prior Peer Group
100.00

136.36

134.81

113.98

131.47

69.96


43

Item 6. Selected Financial Data

SELECTED FIVE-YEAR FINANCIAL DATA

The following table shows selected consolidated financial data derived from our consolidated financial statements set forth in Item 8 of this report. The data should be read in conjunction with Items 1 and 2, “Business and Properties,” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this report.
 
 
 
          Year Ended December 31,
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
 
(In millions, except per share data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Oil, gas and NGL revenues(1)
 
$
2,288

 
$
1,857

 
$
1,562

 
$
1,824

 
$
1,484

Income (loss) from continuing operations
 
650

 
73

 
(922
)
 
427

 
429

Net income (loss)
 
900

 
147

 
(1,184
)
 
539

 
523

Earnings (loss) per share:
 
 
 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
 
 
 
 
     Income (loss) from continuing operations
 
$
4.71

 
$
0.39

 
$
(6.85
)
 
$
3.16

 
$
3.20

Diluted earnings (loss) per share
 
6.52

 
0.94

 
(8.80
)
 
3.99

 
3.91

Weighted-average number of shares outstanding for diluted earnings (loss) per share
 
138

 
136

 
135

 
135

 
134

Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
9,598

 
$
9,321

 
$
7,912

 
$
8,991

 
$
7,494

Long-term debt
 
2,892

 
3,694

 
3,045

 
3,006

 
2,304

 _________________
(1) Continuing operations only (excludes Malaysia).

44

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our principal areas of operation include the Mid-Continent, Rocky Mountains and onshore Gulf Coast regions of the United States. Internationally, we have offshore oil developments in China.

To maintain and grow our production and cash flows, we must continue to develop existing proved reserves and locate or acquire new oil and natural gas reserves to replace those reserves being produced. Our revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. Prices for oil, natural gas and NGLs fluctuate widely and affect:

•the amount of cash flows available for capital expenditures;
•our ability to borrow and raise additional capital; and
•the quantity of oil, natural gas and NGLs that we can economically produce.

Crude oil and natural gas prices decreased significantly during the fourth quarter of 2014 and have remained low into the first quarter of 2015. Nevertheless, we had many operational, financial and strategic successes in 2014. As a result, we believe we are better positioned to face the challenges of 2015.

Significant 2014 highlights include:

•
domestic production increased 20% over 2013 to 46.4 MMBOE, excluding approximately 8.5 Bcf of natural gas produced and consumed in operations;
•
domestic liquids production up 38% over 2013;
•
best in class well in each region: Uinta, Anadarko and Williston Basins;
•
net acres in the Anadarko Basin increased to nearly 300,000;
•
our Pearl development in China achieved first oil and commenced production in the fourth quarter;

•
income from operations increased $125 million over 2013 to $575 million;
•
lease operating expense for continuing operations, on a per BOE basis, decreased 5% year-over-year;
•
general and administrative expense for continuing operations, on a per BOE basis, decreased 15% year-over-year;
•
net derivative asset of $613 million recognized, $423 million of which is current;
•
sold our Granite Wash assets for $588 million and used proceeds from the sale to redeem our 2018 Senior Subordinated Notes of $600 million;
•
sold our Malaysia business for $898 million and used the proceeds from the sale to fund 2014 capital expenditures;
•
reduced debt and strengthened our balance sheet through divestitures; and
•
released inaugural Corporate Responsibility Report.

Building on the results of 2014, we have adapted our 2015 business plan to focus on the following goals in response to this period of dramatic oil and natural gas price declines:

•
maintain and prioritize liquidity preservation over reserve and production growth;
•
match capital investments with cash flows from operations;

45

•
allocate the majority of capital to the Anadarko Basin of Oklahoma;
•
implement a plan to reduce gross general and administrative expenses by 10% to 15%; and
•
implement a plan to reduce domestic per unit lease operating costs by approximately 5 to 15%.

While we expect to achieve savings from cost reductions during 2015, given the lower oil and natural gas price environment as compared to 2014, our revenues and operating income are expected to be lower in 2015 as compared to 2014.
Discontinued Operations

During the second quarter of 2013, our businesses in Malaysia and China met the criteria to be classified as held for sale and reported as discontinued operations. In February 2014, Newfield International Holdings Inc., a wholly-owned subsidiary of the Company, closed the sale of our Malaysia business to SapuraKencana Petroleum Berhad, a Malaysian public company, for $898 million. See Note 1, “Organization and Summary of Significant Accounting Policies,” and Note 3, “Discontinued Operations,” to our consolidated financial statements in Item 8 of this report for additional information regarding the sale of our Malaysia business. During 2014, we continued to market our China business with bids due December 2014. Due to the precipitous decline in oil prices in the fourth quarter, we were unable to sell our China business at an acceptable price and determined it was in the Company's best interest to retain the cash flow from the China business. Accordingly, we reclassified this business as continuing operations for all periods presented.

Results of Continuing Operations

Our continuing operations consist of exploration, development and production activities in the United States and China. The production and average realized prices tables below include our Gulf of Mexico operations for 2012. In the 2012 discussion below, we excluded revenue of $116 million and production of 2,369 MBOE related to our Gulf of Mexico assets that were fully divested in the fourth quarter of 2012 in order to provide a more comparable analysis of our continuing operations.

Domestic Revenues.    Revenues from domestic operations of $2.2 billion for the year ended December 31, 2014 were 26% higher than 2013. The increase was primarily due to a 38% year-over-year increase in our liquids production. Increased oil production generated approximately 81% of the total revenue increase due to production increases in our Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 51%, 26% and 26%, respectively. The increase related to higher oil production was partially offset by lower oil prices, which reduced the overall oil volume and price impact to 58% of the total revenue growth. Increased NGL production in the Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 67%, 44% and 35%, respectively, during the year ended December 31, 2014 generated approximately 20% of the total revenue increase. Approximately 18% of the total revenue increase was due to higher natural gas prices received during the year ended December 31, 2014 compared to the year ended December 31, 2013.

Revenues from domestic operations of $1.8 billion for the year ended December 31, 2013 were 32% higher than 2012. The increase was primarily due to higher liquids production and commodity prices in 2013. Our liquids production increased 43% year-over-year. As expected, our natural gas production declined as we continued to focus capital investments on higher-margin liquids production. Approximately 58% of the revenue increase in 2013 was attributable to increases in oil production in our Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 47%, 59% and 18%, respectively. Higher realized oil prices also increased revenues along with this favorable volume variance. Additionally, revenues increased 21% due to year-over-year NGL production increases in the Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 180%, 59% and 23%, respectively, partially offset by lower NGL prices. While natural gas production declined 14% in 2013, a 29% increase in the realized price during the period more than offset the negative production impact on revenue.

China Revenues.    Our China revenues are recorded when oil is lifted and sold, not when it is produced into floating storage facilities. As a result, the timing of liftings may impact period-to-period results.

Revenues from China of $39 million for the year ended December 31, 2014 were 43% lower than 2013. The decrease was primarily due to the temporary shut-in of production in Bohai Bay by the operator during the second and third quarters of 2014 for scheduled repair and maintenance activities, along with a 24% decrease in oil price during 2014. Revenues from China of $69 million for the year ended December 31, 2013 were 20% lower than 2012. The decrease was primarily due to 18% lower production and slightly lower commodity prices.

The following table reflects our production from continuing operations and average realized commodity prices:

46

 
 
2014
 
2013
 
2012
Production/Liftings:
 
 
 
 
 
 
Domestic:(1)
 
 
 
 
 
 
  Crude oil and condensate (MBbls)
 
18,547

 
14,200

 
11,988

  Natural gas (Bcf)
 
118.2

 
116.1

 
143.5

  NGLs (MBbls)
 
8,207

 
5,163

 
2,608

  Total (MBOE)
 
46,448

 
38,706

 
38,521

China:(2)
 
 
 
 
 
 
  Crude oil and condensate (MBbls)
 
499

 
668

 
811

Total continuing operations:
 
 
 
 
 
 
  Crude oil and condensate (MBbls)
 
19,046

 
14,868

 
12,799

  Natural gas (Bcf)
 
118.2

 
116.1

 
143.5

  NGLs (MBbls)
 
8,207

 
5,163

 
2,608

  Total (MBOE)
 
46,946

 
39,374

 
39,332

Average Realized Prices:
 
 
 
 
 
 
Domestic:(3)
 
 
 
 
 
 
  Crude oil and condensate (per Bbl)
 
$
80.40

 
$
86.21

 
$
83.99

  Natural gas (per Mcf)
 
4.11

 
3.39

 
2.64

  NGLs (per Bbl)
 
32.04

 
30.74

 
31.26

  Crude oil equivalent (per BOE)
 
48.41

 
45.91

 
38.10

China:
 
 
 
 
 
 
  Crude oil and condensate (per Bbl)
 
$
78.52

 
$
103.19

 
$
106.53

Total continuing operations:
 
 
 
 
 
 
  Crude oil and condensate (per Bbl)
 
$
80.35

 
$
86.97

 
$
85.42

  Natural gas (per Mcf)
 
4.11

 
3.39

 
2.64

  NGLs (per Bbl)
 
32.04

 
30.74

 
31.26

  Crude oil equivalent (per BOE)
 
48.73

 
46.88

 
39.51

 _________________
(1)
Excludes natural gas produced and consumed in operations of 8.5 Bcf in 2014, 8.1 Bcf in 2013 and 7.8 Bcf in 2012.
(2)
Represents our net share of volumes sold regardless of when produced.
(3)
We had no outstanding derivative contracts related to our NGL production or our production associated with our international operations. Had we included the realized effects of derivative contracts, the domestic average realized prices would have been as follows:
 
 
2014
 
2013
 
2012
  Crude oil and condensate (per Bbl)
 
$
80.23

 
$
85.77

 
$
84.10

  Natural gas (per Mcf)
 
3.81

 
3.97

 
3.57


Domestic Production.    For the year ended December 31, 2014, production from domestic operations increased 20% primarily due to increased liquids production. Our total 2014 domestic liquids production increased 38% over the prior year due to the success of our liquids-focused drilling programs. Almost 60% of the increase in total liquids was attributable to higher margin crude oil. Natural gas production increased 2% due to associated gas production generated by our liquids-focused drilling programs.

For the year ended December 31, 2013, production from domestic operations increased 7% over the prior year. Crude oil and NGL production increased 43% in 2013 but was partially offset by decreases in natural gas production across our domestic regions. The decrease in natural gas production was due to natural decline as a result of reduced investment in natural gas wells. More than half of the increase in total liquids in 2013 was attributable to higher margin crude oil.

China Production/Liftings.    For the year ended December 31, 2014, production from China decreased 25% compared to the same period in 2013 primarily due to the temporary shut-in of production in Bohai Bay by the operator between May and

47

August 2014 for scheduled repairs and maintenance activities. Production resumed in August 2014; however, we had not accumulated sufficient quantities to schedule a lifting during the remainder of the year. Liftings from Bohai Bay are expected to resume in the first quarter of 2015. The decrease in liftings from Bohai Bay was partially offset by the first lifting from our Pearl development in December 2014. Our Pearl development achieved first oil in the fourth quarter of 2014 after the repaired LF-7 topside facilities were installed in August 2014.

For the year ended December 31, 2013, production from China decreased 18% compared to the same period in 2012 due to natural production decline combined with no wells drilled in the last nine months of the year.

Operating Expenses.

Year ended December 31, 2014 compared to December 31, 2013

The following table presents information about operating expenses for our continuing operations:
 
 
Unit-of-Production
 
Total Amount
 
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
 
2014
 
2013
 
2014
 
2013
 
 
 
(Per BOE)
 
 
 
(In millions)
 
 
Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
  Lease operating
 
$
6.64

 
$
7.13

 
(7
)%
 
$
309

 
$
276

 
12
 %
  Transportation and processing
 
3.74

 
3.54

 
6
 %
 
174

 
137

 
27
 %
  Production and other taxes
 
2.26

 
1.73

 
31
 %
 
105

 
67

 
57
 %
  Depreciation, depletion and amortization
 
18.46

 
17.25

 
7
 %
 
857

 
668

 
28
 %
  General and administrative
 
4.78

 
5.67

 
(16
)%
 
221

 
219

 
1
 %
  Other
 
0.32

 
0.07

 
357
 %
 
15

 
3

 
489
 %
      Total operating expenses
 
36.21

 
35.38

 
2
 %
 
1,681

 
1,370

 
23
 %
China:
 
 
 
 
 
 
 
 
 
 
 
 
  Lease operating
 
$
24.05

 
$
11.99

 
101
 %
 
$
12

 
$
8

 
51
 %
  Production and other taxes
 
11.20

 
17.82

 
(37
)%
 
6

 
12

 
(53
)%
  Depreciation, depletion and amortization
 
25.87

 
26.47

 
(2
)%
 
13

 
17

 
(27
)%
  General and administrative
 
1.11

 
—

 
100
 %
 
1

 
—

 
100
 %
      Total operating expenses
 
62.23

 
56.28

 
11
 %
 
32

 
37

 
(17
)%
Total Continuing Operations:
 
 
 
 
 
 
 
 
 
 
 
 
  Lease operating
 
$
6.83

 
$
7.20

 
(5
)%
 
$
321

 
$
284

 
13
 %
  Transportation and processing
 
3.70

 
3.48

 
6
 %
 
174

 
137

 
27
 %
  Production and other taxes
 
2.36

 
2.00

 
18
 %
 
111

 
79

 
40
 %
  Depreciation, depletion and amortization
 
18.53

 
17.41

 
6
 %
 
870

 
685

 
27
 %
  General and administrative
 
4.74

 
5.57

 
(15
)%
 
222

 
219

 
2
 %
  Other
 
0.32

 
0.06

 
433
 %
 
15

 
3

 
489
 %
      Total operating expenses
 
36.48

 
35.73

 
2
 %
 
1,713

 
1,407

 
22
 %

Domestic Operations. For the year ended December 31, 2014, total operating expenses per BOE for domestic operations increased 2% as compared to the year ended December 31, 2013. The primary reasons for the change follow:

•
Lease operating expenses decreased 7% on a per BOE basis. Higher production volumes, coupled with flat year-over-year well repair costs in all areas, generated approximately 60% of the per BOE reduction. The remaining decrease relates primarily to successful water and compression cost management initiatives in our Williston Basin, Mid-Continent and onshore Gulf Coast areas.

48

•
Transportation and processing expense increased 6% on a per BOE basis primarily due to a 59% increase in NGL volumes processed during 2014.
•
Production and other taxes as a percent of revenue increased 1%. Approximately one-half of this increase is the result of higher tax incentives as well as an ad valorem tax true-up in 2013. The remaining increase, on a percent of revenue basis, is primarily due to the significant growth of our Williston Basin production, which is subject to a higher production tax rate. On a per BOE basis, the increase is driven by increased liquids production as a percent of total production, and the associated increase in average revenue per BOE produced from $45.91 for the year ended December 31, 2013 to $48.41 for the year ended December 31, 2014.
•
Total depreciation, depletion and amortization (DD&A) increased 28% primarily due to the 20% increase in production volumes in 2014 compared to 2013, combined with a 7% increase in the cost per unit of production. The increased cost per unit of production is primarily due to the transfer of approximately $760 million of unevaluated property costs into the full cost pool amortization base during the year. The majority of the costs were transferred in the fourth quarter in response to the significant decrease in oil and natural gas prices and the resulting impact on our future development plans.
•
General and administrative (G&A) expense on a per BOE basis decreased 16% primarily due to increased production in 2014 as compared to 2013. G&A expense was flat year-over-year as increased employee-related expenses in 2014 were offset by higher capitalization of direct internal costs. Employee-related expenses increased by $32 million for stock-based compensation, primarily due to our Stockholder Value Appreciation Program, which achieved three payout targets in 2014 compared to one in 2013 (see Note 11, "Stock-based Compensation," to our consolidated financial statements in Item 8 of this report). The increase in stock-based compensation expense was partially offset by a decrease of $13 million in labor-related costs associated primarily with the centralization of certain functions during the second half of 2013. For the year ended December 31, 2014, we capitalized $135 million ($2.90 per BOE) of direct internal costs as compared to $107 million ($2.77 per BOE) during the comparable period of 2013. This increase is primarily due to a higher portion of the costs associated with stock-based liability awards earned by employees who are directly involved with our exploration and development activities.
•
Other operating expense increased $12 million primarily due to equipment inventory value impairments and legal settlements during 2014 as compared to 2013.

China Operations. For the year ended December 31, 2014, total operating expenses per BOE for our China operations increased 11% compared to the year ended December 31, 2013. Results for 2014 include activity from Bohai Bay and our Pearl development, whereas 2013 results include only Bohai Bay.

LOE per barrel increased over 100% as a result of one-time production preparation costs associated with our Pearl development, a higher tariff on crude oil produced from our Pearl development and higher operating costs associated with deep water operations for Pearl. These increases were partially offset by a 37% decrease in production and other taxes per BOE, primarily due to the timing of liftings in China. Approximately 60% of our liftings in China were in the fourth quarter of 2014, which had significantly lower realized prices than 2013.
 
We expect that 2015 revenues and expenses in China will increase over 2014 as we execute our Pearl development plan. In January 2015, we completed one well, and we plan to drill 4 additional wells during the year. The Pearl development is expected to reach peak production by mid-2015.


49

Year ended December 31, 2013 compared to December 31, 2012

The following table presents information about our operating expenses for our continuing operations:

 
 
Unit-of-Production
 
Total Amount
 
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
 
2013
 
2012
 
2013
 
2012
 
 
 
(Per BOE)
 
 
 
(In millions)
 
 

Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
  Lease operating
 
$
7.13

 
$
7.75

 
(8
)%
 
$
276

 
$
299

 
(8
)%
  Transportation and processing
 
3.54

 
2.78

 
27
 %
 
137

 
107

 
28
 %
  Production and other taxes
 
1.73

 
1.74

 
(1
)%
 
67

 
67

 
—
 %
  Depreciation, depletion and amortization
 
17.25

 
17.74

 
(3
)%
 
668

 
683

 
(2
)%
  General and administrative
 
5.67

 
5.48

 
3
 %
 
219

 
211

 
4
 %
  Ceiling test impairment
 
—

 
38.63

 
(100
)%
 
—

 
1,488

 
(100
)%
  Other
 
0.07

 
0.38

 
(82
)%
 
3

 
15

 
(83
)%
      Total operating expenses
 
35.38

 
74.50

 
(53
)%
 
1,370

 
2,870

 
(52
)%
China:
 
 
 
 
 
 
 
 
 
 
 
 
  Lease operating
 
$
11.99

 
$
8.95

 
34
 %
 
$
8

 
$
7

 
10
 %
  Production and other taxes
 
17.82

 
22.49

 
(21
)%
 
12

 
18

 
(35
)%
  Depreciation, depletion and amortization
 
26.47

 
26.20

 
1
 %
 
17

 
21

 
(17
)%
      Total operating expenses
 
56.28

 
57.64

 
(2
)%
 
37

 
46

 
(20
)%
Total Continuing Operations:
 
 
 
 
 
 
 
 
 
 
 
 
  Lease operating
 
$
7.20

 
$
7.77

 
(7
)%
 
$
284


$
306

 
(7
)%
  Transportation and processing
 
3.48

 
2.72

 
28
 %
 
137

 
107

 
28
 %
  Production and other taxes
 
2.00

 
2.17

 
(8
)%
 
79

 
85

 
(8
)%
  Depreciation, depletion and amortization
 
17.41

 
17.91

 
(3
)%
 
685

 
704

 
(3
)%
  General and administrative
 
5.57

 
5.36

 
4
 %
 
219

 
211

 
4
 %
  Ceiling test impairment
 
—

 
37.84

 
(100
)%
 
—

 
1,488

 
(100
)%
  Other
 
0.06

 
0.37

 
(84
)%
 
3

 
15

 
(83
)%
      Total operating expenses
 
35.73

 
74.15

 
(52
)%
 
1,407

 
2,916

 
(52
)%

Domestic Operations. For the year ended December 31, 2013, total operating expenses for domestic operations increased 7% but were flat on a per BOE basis after adjusting for the 2012 ceiling test writedown and operating expenses of $102 million attributable to Gulf of Mexico assets that were fully divested in the fourth quarter of 2012. The components of significant period-to-period change for operating expenses excluding Gulf of Mexico related expenses related to 2012 are as follows:

•
Lease operating expense decreased 2% on a per BOE basis primarily due to lower well repair costs in our Williston Basin, Mid-Continent and onshore Gulf Coast areas.
•
Transportation and processing expense increased 22% on a per BOE basis primarily due to increased NGL volumes as a percent of total production resulting from our liquids-focused drilling program.
•
Production and other taxes were flat on an actual cost and per unit basis. However, on a percent of revenue basis, they fell approximately 1%. This rate reduction is primarily attributable to production tax credits received in the Mid-Continent, onshore Gulf Coast and Uinta basins plus an $8 million adjustment of ad valorem taxes in the Uinta Basin previously expensed in 2012 and prior years. Without the ad valorem tax adjustment in the Uinta Basin, production and other taxes on a percent of revenue basis would have decreased by less than a half of a percent.

50

•
General and administrative expense increased during 2013 primarily due to employee-related expenses associated with our Voluntary Severance Program and Stockholder Value Appreciation Program (see Note 11, "Stock-Based Compensation," to our consolidated financial statements in Item 8 of this report), partially offset by the cost savings generated by the centralization of several administrative functions. During 2013, we capitalized $107 million ($2.77 per BOE) of direct internal costs as compared to $95 million ($2.45 per BOE) during 2012.
•
In the fourth quarter of 2012, we recorded a ceiling test writedown of $1.5 billion due to a net decrease in the discounted value of our proved reserves. The primary reason for the change in value was negative price-related reserve revisions as a result of a 33% decrease in the natural gas SEC pricing.
•
Other expenses in 2012 of $15 million included a writedown of $8 million of subsea wellhead inventory that was not included in the sale of our Gulf of Mexico assets and contract termination costs of $6 million in consideration of other services.

China Operations. For the year ended December 31, 2013, total operating expenses for China operations decreased by $9 million compared to the same period in 2012. This overall decrease is consistent with the 18% decrease in production volumes in 2013 compared to 2012.

Interest Expense. The following table presents information about interest expense for each of the following years ended
December 31:
 
 
2014
 
2013
 
2012
 
 
(In millions)
Gross interest expense:
 
 
 
 
 
 
Credit arrangements
 
$
10

 
$
11

 
$
9

Senior notes
 
101

 
101

 
73

Senior subordinated notes
 
89

 
93

 
122

Other
 
—

 
—

 
1

Total gross interest expense
 
200

 
205

 
205

Capitalized interest
 
(53
)
 
(53
)
 
(68
)
Net interest expense
 
$
147

 
$
152

 
$
137


Gross interest expense decreased slightly in 2014 as compared to 2013, due to the redemption of our 7⅛% Senior Subordinated Notes due 2018 in October 2014. Gross interest expense remained flat in 2013 as compared to 2012 due to the restructuring of our senior notes in 2012. See Note 9, “Debt,” to our consolidated financial statements in Item 8 of this report.

Interest expense associated with oil and gas properties excluded from amortization is capitalized into oil and gas properties. The average balance of oil and gas properties excluded from amortization was consistent for the first three quarters of 2014 resulting in flat capitalized interest in 2014 as compared to 2013. We expect to see less capitalized interest in 2015 due to the reduction of oil and gas properties excluded from amortization at December 31, 2014. Capitalized interest decreased in 2013 as compared to 2012, due to a reduction in our average balance of oil and gas properties excluded from amortization.

Commodity Derivative Income (Expense).    The fluctuations in commodity derivative income (expense) from period to period are due to the volatility of oil and natural gas prices and changes in our outstanding derivative contracts during these periods. Commodity derivative income for the year ended December 31, 2014 was $610 million, which was primarily comprised of unrealized gains of $649 million related to the change in value of derivative contracts due to changes in commodity prices, offset by $39 million of realized losses associated with derivative contract settlements. Commodity derivative expense for the year ended December 31, 2013 was $97 million, which was primarily comprised of unrealized losses of $157 million related to the change in value of derivative contracts due to changes in commodity prices, offset by $60 million of realized gains associated with derivative contract settlements. See Note 5, "Derivative Financial Instruments," and Note 8, "Fair Value Measurements," to our consolidated financial statements in Item 8 of this report.

Taxes.    The effective tax rates for continuing operations for the years ended December 31, 2014, 2013 and 2012 were 37%, 64% and 33%, respectively. Our effective tax rate for all periods was different than the federal statutory rate of 35% due to non-deductible expenses, state income taxes, the differences between international and U.S. federal statutory rates, and the impact of our China earnings being taxed both in the U.S and China. This double taxation is a byproduct of our federal net operating loss (NOL) position which limits our ability to utilize related foreign tax credits (FTC) until our remaining NOLs are

51

utilized. As a result of our earnings in China being taxed in both the U.S. and China, we expect our effective tax rate for future China earnings to be approximately 60%. We expect the U.S. portion of the rate to be a 35% tax rate, all of which is expected to be deferred taxes.

Our effective tax rate for our domestic operations generally approximates 37%. For the year ended 2014, our effective tax rate was 37% for continuing operations as the majority of our income from continuing operations resulted from our domestic business, which was only taxable in the U.S. As a result of our December 2012 decision to repatriate earnings from our international operations, we experienced fluctuation in our effective tax rates in 2013 and 2012 due to these earnings being taxed both in the U.S. and the local countries. Please see the discussion and tables in Note 10, “Income Taxes,” to our consolidated financial statements in Item 8 of this report.

Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices; the timing, amount and location of future production; operating expenses; and capital costs.

Results of Discontinued Operations - Malaysia

Revenues and Liftings.  Our Malaysia revenues were primarily from the sale of crude oil. Substantially all of the crude oil from our offshore Malaysia operations was produced into FPSOs and "lifted" and sold periodically as barge quantities were accumulated. Revenues were recorded when oil was lifted and sold, not when it was produced into FPSOs or onshore storage terminals. As a result, timing of liftings impacted period-to-period results. In February 2014, we closed the sale of our Malaysia business. See Note 1, “Organization and Summary of Significant Accounting Policies” and Note 3, “Discontinued Operations,” to our consolidated financial statements appearing in Item 8 of this report for additional information regarding the sale.

For the year ended December 31, 2014, revenues from discontinued operations of $90 million were 89% lower than 2013, due to the sale of our Malaysia business in February 2014. Revenues of $823 million for 2013 were 18% lower than 2012, primarily due to fewer liftings of crude oil. The average realized price per BOE remained essentially flat during 2012, 2013 and 2014 through the close date of the sale. Our 2013 total liftings decreased 18% as compared to 2012. Approximately 65% of the decrease in liftings was due to natural decline. The remainder of the decrease was due to the timing of liftings and the terms of the production sharing contracts (PSCs) in Malaysia, which reduced entitled production as we reached certain cost recovery milestones.

The following table reflects our production and average realized commodity prices from discontinued operations for each of the following years ended December 31:
 
 
2014
 
2013
 
2012
Production/Liftings:(1)
 
 
 
 
 
 
Crude oil and condensate (MBbls)
 
822

 
7,510

 
9,103

Natural gas (Bcf)
 
—

 
0.5

 
1.2

Total (MBOE)
 
822

 
7,600

 
9,295

Average Realized Prices:
 
 
 
 
 
 
Crude oil and condensate (per Bbl)
 
$
109.86

 
$
109.20

 
$
109.95

Natural gas (per Mcf)
 
—

 
3.65

 
3.89

Crude oil equivalent (per BOE)
 
109.86

 
108.17

 
108.17

________________
(1)
Represents our net share of volumes sold regardless of when produced.

Operating Expenses. The following tables present information about our operating expenses for our discontinued operations.

52


Year ended December 31, 2014 compared to December 31, 2013

 
 
Unit-of-Production
 
Total Amount
 
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
 
2014
 
2013
 
2014
 
2013
 
 
 
(Per BOE)
 
 
 
(In millions)
 
 
Lease operating
 
$
13.76

 
$
15.39

 
(11
)%
 
$
11

 
$
117

 
(90
)%
Production and other taxes
 
31.16

 
35.85

 
(13
)%
 
25

 
272

 
(91
)%
Depreciation, depletion and amortization
 
39.30

 
32.17

 
22
 %
 
33

 
245

 
(87
)%
General and administrative
 
—

 
2.31

 
(100
)%
 
—

 
18

 
(100
)%
Total operating expenses
 
84.22

 
85.71

 
(2
)%
 
69

 
652

 
(89
)%

Our total operating expenses for discontinued operations for 2014 decreased $583 million compared to the same period of 2013 as a result of the sale of our Malaysia business in February 2014.

Year ended December 31, 2013 compared to December 31, 2012

 
 
Unit-of-Production
 
Total Amount
 
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
Year Ended
December 31,
 
Percentage
Increase
(Decrease)
 
 
2013
 
2012
 
2013
 
2012
 
 
 
(Per BOE)
 
 
 
(In millions)
 
 
Lease operating
 
$
15.39

 
$
10.89

 
41
%
 
$
117

 
$
101

 
16
 %
Production and other taxes
 
35.85

 
27.82

 
29
%
 
272

 
259

 
5
 %
Depreciation, depletion and amortization
 
32.17

 
26.94

 
19
%
 
245

 
251

 
(2
)%
General and administrative
 
2.31

 
0.75

 
208
%
 
18

 
7

 
151
 %
Total operating expenses
 
85.71

 
66.40

 
29
%
 
652

 
618

 
6
 %

Our operating expenses for discontinued operations for 2013, stated on a per BOE basis, increased 29% over 2012. The components of the period-to-period change are as follows:

•
LOE per BOE increased 41% ($4.50 per BOE) due to increased service costs related to offshore support operations in Malaysia and mostly-fixed fees associated with producing into onshore storage terminals in Malaysia combined with fewer liftings.
•
Production and other taxes per BOE increased 29% due to the terms of the PSCs in Malaysia, which increased production tax rates subsequent to reaching certain cost recovery milestones.
•
DD&A expense decreased 2% due to an 18% decrease in liftings during 2013 as compared to 2012, partially offset by an increase in the average DD&A rate. Our DD&A rate per BOE increased 19% in 2013 compared to 2012 due primarily to upward revisions of asset retirement costs in 2013 for Malaysia and the costs of unsuccessful wells in offshore Malaysia being included in costs subject to amortization in the second quarter of 2013 without a related increase in reserves.
•
G&A expense increased approximately $11 million ($1.56 per BOE) primarily due to increased employee-related costs and other costs associated with our decision to sell our Malaysia business.

Liquidity and Capital Resources

The following discussion is inclusive of both our continuing and discontinued operations, unless otherwise noted.


53

We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this through drilling programs and property acquisitions, which require substantial capital expenditures. Sustained lower prices for oil, natural gas and NGLs will reduce the amount of oil and gas that we can economically produce and will affect the amount of cash flow available for capital expenditures. Sustained lower commodity prices may also impact our ability to borrow and raise additional capital, as further described below.

We establish a capital budget at the beginning of each calendar year and review it during the course of the year. Our capital budgets (excluding acquisitions) are created based upon our estimate of internally generated sources of cash, as well as the available borrowing capacity of our revolving credit facility and money market lines of credit.
 
During the fourth quarter of 2014 and continuing into the first quarter of 2015, crude oil prices declined significantly primarily due to global supply and demand imbalances. Given the future uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, we have reduced our planned capital spending for 2015 to more closely match our expected cash flows and have decided to optimize long-term liquidity preservation over short-term reserve and production growth. We expect our 2015 budget will be financed through our cash flows from operations (inclusive of realized derivative contract gains and losses) and borrowings under our credit facility, as needed. Approximately 82% of our expected 2015 domestic oil and gas sales (excluding NGLs) supporting the current 2015 capital budget are partially protected against oil and gas price volatility using derivative contracts. For further discussion of our derivative activities, see Note 5, "Derivative Financial Instruments," to our consolidated financial statements in Item 8 of this report. Our 2015 capital budget, excluding estimated capitalized interest and direct internal costs of approximately $120 million, is expected to be approximately $1.2 billion.

At December 31, 2014, the values of our U.S. and China cost center ceilings were calculated based upon SEC pricing of $4.35 per MMBtu for natural gas and $94.98 per barrel for oil. Using these prices, our ceilings for the U.S. and China exceeded the net capitalized costs of oil and gas properties by approximately $400 million and $150 million, respectively, net of tax, and as such, no ceiling test writedown was required. Holding all other factors constant, it is likely that we will experience a ceiling test writedown in the U.S. and China in the first quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes. Subject to these numerous factors and inherent limitations, we believe that an impairment in the first quarter of 2015 could exceed $750 million. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.

Actual capital expenditure levels may vary significantly due to many factors, including drilling results; oil, natural gas and NGL prices; industry conditions; the prices and availability of goods and services; and the extent to which properties are acquired or non-strategic assets are sold. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. We believe we have the operational flexibility to react quickly with our capital expenditures to changes in circumstances or fluctuations in our cash flows.

We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate our available alternative sources of liquidity, including accessing debt and equity capital markets in light of current and expected economic conditions. We believe that our liquidity position and ability to generate cash flows from our operations will be adequate to fund 2015 operations and continue to meet our other obligations.

Credit Arrangements and Other Financing Activities.    We maintain a revolving credit facility of $1.4 billion that matures in June 2018, as well as money market lines of credit of $195 million. At December 31, 2014, we had $345 million of LIBOR based loans outstanding against our revolving credit facility and $101 million outstanding against our money market lines of credit. In October 2014, we completed the redemption of our $600 million aggregate principal of 7⅛% Senior Subordinated Notes due 2018. The transaction included a premium payment of approximately $14 million. At December 31, 2014, we had no scheduled maturities of senior or senior subordinated notes until 2020. For a more detailed description of the terms of our credit arrangements and senior and senior subordinated notes, please see Note 9, “Debt,” to our consolidated financial statements in Item 8 of this report.

Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and maintenance of a ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and certain noncash items to interest expense of at least 3.0 to 1.0. At December 31, 2014, we were in compliance with all of our debt covenants. We entered this challenging commodity price environment with strong debt covenant-related financial ratios and do not foresee this changing in 2015. For a more detailed description of the terms of our credit arrangements, please see Note 9, “Debt ,” to our consolidated financial statements in Item 8 of this report.

54

As of February 20, 2015, we had outstanding borrowings of $610 million and available borrowing capacity of approximately $790 million under our revolving credit facility. In addition, we had outstanding borrowings under our money market lines of credit of $85 million.

Working Capital.    Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements, changes in the fair value of our outstanding commodity derivative instruments as well as the timing of receiving reimbursement of amounts paid by us for the benefit of joint venture partners. Without the effects of commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital.

At December 31, 2014 and 2013, we had negative working capital of $161 million and $389 million, respectively. The changes in our working capital from 2013 to 2014 are primarily a result of a $485 million increase in the fair value of our current net derivative asset during 2014 combined with working capital reductions associated with the sale of our Malaysia business (February 2014) and our Granite Wash assets (September 2014). The remaining change is due to the timing of the collection of receivables; the timing of crude oil liftings in our China operations; drilling activities; payments made by us to vendors and other operators; and the timing and amount of advances received from our joint operations.

Cash Flows from Operations.    Our primary source of capital and liquidity are cash flows from operations, which are primarily affected by the sale of oil, natural gas and NGLs, as well as commodity prices, net of the effects of settled derivative contracts, as well as changes in working capital.

Our net cash flows from operations were approximately $1.4 billion in 2014 (includes $3 million of cash flows from our Malaysia discontinued operations), $1.4 billion in 2013 and $1.1 billion in 2012. Despite selling our Malaysia business, which provided approximately $249 million of our 2013 cash flows from operations, our 2014 cash flows from operations were relatively flat compared to 2013. This is a result of increased domestic production, strong pricing during the first nine months of the year and a $0.42 per BOE decrease in domestic operating expenses (excluding non-cash DD&A expense) during the year.

Cash Flows from Investing Activities.    Net cash used in investing activities for 2014 was $660 million compared to $2.1 billion for 2013. The decrease in net cash used in 2014 investing activities is primarily due to net proceeds of $809 million received from the sale of our Malaysia business and proceeds of approximately $620 million from the sale of our Granite Wash and other assets. Our investment levels in our oil and gas properties were relatively consistent during 2014 and 2013 as we executed our plan in a stable commodity price environment into third quarter 2014. Due to the dramatic commodity price decline in fourth quarter 2014, we expect a significant decrease in our investments during 2015.

Cash Flows from Financing Activities.    Net cash used in financing activities for 2014 was $808 million compared to net cash provided by financing activities of $620 million for 2013. During 2014, we reduced our outstanding borrowings under our revolving credit facility and money market lines of credit by $203 million and redeemed our $600 million aggregate principal of 7⅛% Senior Subordinated Notes due 2018 using the proceeds from the sale of our Granite Wash assets.

Capital Expenditures.    Our capital investments for continuing operations for 2014 increased 5% compared to 2013, due to accelerating the development of our domestic assets during 2014. The table below summarizes our capital investments.

55

 
Twelve Months Ended 
 December 31,
 
2014
 
2013
 
(In millions)
Continuing operations:
 
 
 
     Exploitation and development
$
1,411

 
$
1,391

     Exploration (exclusive of exploitation and leasehold)
346

 
249

     Acquisitions
33

 
72

     Leasing proved and unproved property (leasehold)
119

 
90

     Pipeline spending
9

 
20

     Plug and abandonment settlements
8

 
8

        Total continuing operations
1,926

 
1,830

Discontinued operations
12

 
199

         Total
$
1,938

 
$
2,029



56


Contractual Obligations

The table below summarizes our significant contractual obligations due by year as of December 31, 2014. 
 
 
 
 
Year Ended December 31,
 
 
 
 
Total
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
 
(In millions)
Long-term debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving credit facility
 
$
345

 
$
—

 
$
—

 
$
—

 
$
345

 
$
—

 
$
—

Money market lines of credit
 
101

 
—

 
—

 
—

 
101

 
—

 
—

5¾% Senior Notes due 2022
 
750

 
—

 
—

 
—

 
—

 
—

 
750

5⅝% Senior Notes due 2024
 
1,000

 
—

 
—

 
—

 
—

 
—

 
1,000

6⅞% Senior Subordinated Notes due 2020
 
700

 
—

 
—

 
—

 
—

 
—

 
700

Total long-term debt
 
2,896

 
—

 
—

 
—

 
446

 
—

 
2,450

Other obligations(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest payments
 
1,181

 
156

 
156

 
156

 
152

 
148

 
413

Asset retirement obligations
 
186

 
3

 
2

 
5

 
14

 
3

 
159

Operating leases and other(2)
 
443

 
240

 
67

 
28

 
26

 
23

 
59

Firm transportation
 
389

 
72

 
85

 
82

 
63

 
52

 
35

Total other obligations
 
2,199

 
471

 
310

 
271

 
255

 
226

 
666

Total contractual obligations
 
$
5,095

 
$
471

 
$
310

 
$
271

 
$
701

 
$
226

 
$
3,116

_________________
(1)
Excludes assets and liabilities associated with our derivative contracts. For a discussion regarding our derivative contracts, see Note 5, "Derivative Financial Instruments," to our consolidated financial statements in Item 8 of this report, which is incorporated herein by reference.
(2)
Includes agreements for office space, drilling rigs and other equipment, as well as certain service contracts. The majority of these obligations are related 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 significantly less than the gross obligation disclosed.

We have various oil and gas production volume delivery commitments that are related to our domestic operations. Given the recent decline in oil and natural gas prices and the related impact on our 2015 planned capital investments as well as the potential impact on development plans in future years, we could fail to deliver the minimum production required under these commitments. In the event that we are unable to meet our crude oil volume delivery commitments, we would incur deficiency fees ranging from $1.83 to $6.50 per barrel. See Items 1 and 2, “Business and Properties” for a description of our production and proved reserves. As of December 31, 2014, our delivery commitments through 2025 were as follows: 
 
 
Total
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
Natural gas (MMMBtus)
 
15,372

 
15,372

 
—

 
—

 
—

 
—

 
—

Oil (MBbls)(1)
 
108,664

 
6,570

 
13,908

 
13,870

 
13,870

 
13,870

 
46,576

_________________
(1)
Our oil delivery commitments include commitments with Salt Lake City, Utah refiners. Our delivery commitments are for approximately 18,000 barrels of oil per day through 2020 and an additional 20,000 barrels of oil per day expected to start in 2016 and continuing through 2025. The 20,000 barrel per day delivery commitment represents approximately 7,300 MBbls of our committed oil volumes for each of the years 2016 through 2025. The timing may change due to timing of the refinery expansion completion. These commitments relate to our Uinta Basin production.

Commitments under Joint Operating Agreements.    Most of our properties are operated through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and

57

in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator if a non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses.

Oil and Gas Derivatives

We use derivative contracts to manage the variability in cash flows caused by commodity price fluctuations associated with our anticipated future oil and gas production for the next 24 to 36 months. As of December 31, 2014, we had no outstanding derivative contracts related to our NGL production or on production associated with our discontinued operations. We do not use derivative instruments for trading purposes.

For a further discussion of our derivative activities, see "Critical Accounting Policies and Estimates — Commodity Derivative Activities" below and "Oil, Natural Gas and NGL Prices" in Item 7A of this report. See the discussion and tables in Note 5, "Derivative Financial Instruments," and Note 8, "Fair Value Measurements," to our consolidated financial statements in Item 8 of this report for additional information regarding the accounting applicable to our oil and gas derivative contracts, a listing of open contracts and the estimated fair market value of those contracts as of December 31, 2014.

Between January 1, 2015 and February 20, 2015, we did not enter into additional derivative contracts.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or for any other purpose.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Described below are the most significant policies we apply in preparing our financial statements, some of which are subject to alternative treatments under generally accepted accounting principles. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with the Audit Committee of our Board of Directors. See Note 1, “Organization and Summary of Significant Accounting Policies,” to our consolidated financial statements in Item 8 of this report for a discussion of additional accounting policies and estimates we make.

For discussion purposes, we have divided our significant policies into four categories. Set forth below is an overview of each of our significant accounting policies by category.

•
We account for our oil and gas activities under the full cost method.    This method of accounting requires the following significant estimates:

•
quantity of our proved oil and gas reserves;
•
costs withheld from amortization; and
•
future costs to develop and abandon our oil and gas properties.
•
Accounting for business combinations requires estimates and assumptions regarding the fair value of the assets and liabilities of the acquired company.

58

•
Accounting for commodity derivative activities requires estimates and assumptions regarding the fair value of derivative positions.
•
Stock-based compensation costs require estimates and assumptions regarding the grant date fair value of awards, the determination of which requires significant estimates and subjective judgments.

Oil and Gas Activities.    Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available — successful efforts and full cost. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed, while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and gas properties under the successful efforts method is a two-step test that compares the carrying value of the properties to the undiscounted cash flows to see if an impairment is required. If required, the impairment is the difference between the carrying value of individual oil and gas properties and their estimated fair value using forward-looking prices. Impairment under the full cost method requires an evaluation of the carrying value of oil and gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using SEC pricing, costs in effect at year-end and a 10% discount rate.

We use the full cost method of accounting for our oil and gas activities. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas activities.

Proved Oil and Gas Reserves.    Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization (DD&A) expense and the full cost ceiling limitation. Proved oil and gas reserves are the estimated quantities of oil and gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs based on SEC pricing and under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil, gas and NGL prices, operating costs and expected performance from a given reservoir also will result in future revisions to the amount of our estimated proved reserves. All reserve information in this report is based on estimates prepared by our petroleum engineering staff.

Depreciation, Depletion and Amortization.    Estimated proved oil, gas and NGL reserves are a significant component of our calculation of DD&A expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test writedown. To change our diluted earnings per share for continuing operations by $0.01 for the year ended December 31, 2014, our domestic DD&A rate would need to change by $0.17 per BOE, which would require a change in the estimate of our domestic proved reserves of approximately 1%, or 6 MMBOE. Our China DD&A rate would need to change by $1.24 per BOE, which would require a change in the estimate of our China proved reserves of approximately 5%, or 1 MMBOE.

Full Cost Ceiling Limitation.    Under the full cost method, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of costs associated with our oil and gas properties that can be capitalized on our balance sheet. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. The ceiling value of oil, gas and NGL reserves is calculated based on SEC pricing and costs in effect as of the last day of the quarter.

At December 31, 2014, the values of our U.S. and China cost center ceilings were calculated based upon SEC pricing of $4.35 per MMBtu for natural gas and $94.98 per barrel for oil. Using these prices, our ceilings for the U.S. and China exceeded the net capitalized costs of oil and gas properties by approximately $400 million and $150 million, respectively, net of tax, and as such, no ceiling test writedown was required. Holding all other factors constant, it is likely that we will experience a ceiling test writedown in the U.S. and China in the first quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes. Subject to these numerous factors and inherent limitations, we believe that an impairment in the first quarter of 2015 could exceed $750 million. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.


59

Further SEC pricing declines or downward revisions to our estimated proved reserves could result in additional writedowns of our oil and gas properties in subsequent periods.

Costs Withheld From Amortization.    Costs associated with unevaluated properties are excluded from our amortization base until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed quarterly for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred, or a charge is made against earnings if the costs were incurred in a country for which a reserve base has not been established. If a reserve base for a country in which we are conducting operations has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information.

In addition, a portion of incurred (if not previously included in the amortization base) and estimated future development costs associated with qualifying major development projects may be temporarily excluded from amortization. To qualify, a project must require significant costs to ascertain the quantities of proved reserves attributable to the properties under development (e.g., the installation of an offshore production platform from which development wells are to be drilled). Incurred and estimated future development costs are allocated between completed and future work. Any temporarily excluded costs are included in the amortization base upon the earlier of when the associated reserves are determined to be proved or impairment is indicated.

Our decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involve a significant amount of judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and results of drilling on adjacent acreage. At December 31, 2014, we had a total of $677 million of costs excluded from the amortization base of our respective full cost pools, all of which related to our domestic full cost pool. Inclusion of some or all of our domestic unevaluated property costs in our domestic full cost pool, without adding any associated reserves, would not have resulted in a ceiling test writedown as the after-tax impact would be less than our ceiling test cushion.

Future Development and Abandonment Costs.    Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our gathering systems, production platforms and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, water depth, reservoir depth and characteristics, market demand for equipment, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and abandonment costs annually, or more frequently if an event occurs or circumstances change that would affect our assumptions and estimates.

The accounting guidance for future abandonment costs requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.

Holding all other factors constant, if our estimate of future development and abandonment costs is revised upward, earnings would decrease due to higher DD&A expense. Likewise, if these estimates are revised downward, earnings would increase due to lower DD&A expense. To change our diluted earnings per share for continuing operations by $0.01 for the year ended December 31, 2014, our domestic DD&A rate would need to change by $0.17 per BOE which would require a change in estimate of our domestic future development and abandonment costs of approximately 2%, or $111 million. Our China DD&A rate would need to change by $1.24 per BOE which would require a change in estimate of our China future development and abandonment costs of approximately 104%, or $29 million.

Allocation of Purchase Price in Business Combinations.    As part of our growth strategy, we monitor and screen for potential acquisitions of oil and gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves

60

and unproved properties. To the extent the consideration paid exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value allocated to recoverable oil and natural gas reserves and unproved properties is subject to the cost center ceiling as described under “— Full Cost Ceiling Limitation” above. The accounting standard for business combinations establishes how a purchaser recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The standard also sets forth guidance related to the recognition, measurement and disclosure related to goodwill acquired in a business combination or gains associated with a bargain purchase transaction.

Commodity Derivative Activities.    Under accounting rules, we may elect to designate certain derivative contracts that qualify for hedge accounting as cash flow hedges against the price that we will receive for our future oil and gas production. We do not designate future price-risk management activities as accounting hedges. Because derivative contracts not designated for hedge accounting are accounted for on a mark-to-market basis, we have in the past experienced, and are likely in the future to experience non-cash volatility in our reported earnings during periods of commodity price volatility. As of December 31, 2014, we had net derivative assets of $613 million, of which 54%, based on total contracted volumes, was measured based upon our valuation model (i.e. Black-Scholes) and, as such, is classified as a Level 3 fair value measurement.

In determining the amounts to be recorded for our open derivative contracts, we are required to estimate the fair value of the derivative. Our valuation models for derivative contracts are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying commodities, as well as other relevant economic measures. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative contracts, and the resulting estimated future cash inflows or outflows over the lives of the contracts are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility, as well as changes in future price forecasts, regional price differences and interest rates. As a result, the value of these contracts at their respective settlement dates could be significantly different than the fair value as of December 31, 2014. We periodically validate our valuations using independent third-party quotations.

The determination of the fair value of derivative instruments incorporates various factors which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties.

Stock-Based Compensation.    We apply a fair value-based method of accounting for stock-based compensation which requires recognition in the financial statements of the cost of services received in exchange for awards of equity instruments based on the grant date fair value of those awards. For equity awards, compensation expense is based on the fair value on the grant or modification date and is recognized in our financial statements over the vesting period. We utilize the Black-Scholes option-pricing model to measure the fair value of stock options and a Monte Carlo lattice-based model for our performance and market-based restricted stock and restricted stock units. We also have cash-settled restricted stock units as well as a Stockholder Value Appreciation Program that are accounted for under the liability method which requires us to recognize the fair value of each award based on the underlying share price at the end of each period. See Note 11, “Stock-Based Compensation,” to our consolidated financial statements in Item 8 of this report for a full discussion of our stock-based compensation.

New Accounting Requirements

In August 2014, the FASB issued guidance regarding disclosures of uncertainties about an entity's ability to continue as a going concern. The guidance applies prospectively to all entities, requiring management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern and disclose certain information when substantial doubt is raised. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We do not expect this guidance to impact our Company.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We are currently evaluating the impact of this guidance on our financial statements.

In April 2014, the FASB issued guidance regarding the reporting of discontinued operations. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance

61

is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect this guidance to impact our Company.

Regulation

Exploration and development and the production and sale of oil, gas and NGLs are subject to extensive federal, state, provincial, tribal, local and international regulations. An overview of these regulations is set forth in Items 1 and 2, “Business and Properties — Regulation.” We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Please see the discussion under the caption “We are subject to complex laws and regulatory actions that can affect the cost, manner, feasibility or timing of doing business,” in Item 1A of this report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from changes in oil, natural gas and NGL prices, interest rates and foreign currency exchange rates as discussed below.

Oil, Natural Gas and NGL Prices

Our decision on the quantity and price at which we choose to enter into derivative contracts is based in part on our view of current and future market conditions. While the use of derivative contracts can limit or reduce the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements. In addition, the use of derivative contracts may involve basis risk. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative contracts also involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At December 31, 2014, ten of our 16 counterparties accounted for approximately 85% of our contracted volumes with no single counterparty accounting for more than 15%. Of our expected 2015 crude oil production, 87% is protected against price volatility through the use of derivative contracts. Almost 90% of our crude oil derivative structures include short puts. Short puts effectively limit our downward price protection below the weighted average of our short puts of $71.83 per barrel. If the market price remains below $71.83 per barrel, we receive the market price for our associated production plus the difference between our short puts and the associated floors or fixed-price swaps, which average $18.19 per barrel. We do not have any natural gas derivative contracts that include short puts. For a further discussion of our derivative activities, see the information under the captions “Oil and Gas Derivatives” and “Critical Accounting Policies and Estimates” in Item 7 of this report and the discussion and tables in Note 5, “Derivative Financial Instruments,” to our consolidated financial statements in Item 8 of this report.

Interest Rates

At December 31, 2014, our debt was comprised of:
 
 
Fixed Rate Debt
 
Variable Rate Debt
 
 
(In millions)
Revolving credit facility and money market lines of credit
 
$
—

 
$
446

5¾% Senior Notes due 2022
 
750

 
—

5⅝% Senior Notes due 2024
 
1,000

 
—

6⅞% Senior Subordinated Notes due 2020
 
696

 
—

 
 
$
2,446

 
$
446


We consider our interest rate exposure to be minimal because 85% of our obligations were at fixed rates as of December 31, 2014, and our variable rate debt was at a weighted-average interest rate of approximately 2%. A 10% increase in LIBOR would not materially impact our interest costs on debt outstanding at December 31, 2014, but would decrease the fair value of our outstanding debt, as well as increase interest costs associated with future debt issuances or borrowings under our revolving credit facility and money market lines of credit.

62


Foreign Currency Exchange Rates

The functional currency for our foreign operations is the U.S. dollar. To the extent that business transactions in a foreign country are not denominated in the respective country’s functional currency, we are exposed to foreign currency exchange risk. We consider our current risk exposure to exchange rate movements, based on net cash flows, to be immaterial. We did not have any open derivative contracts related to foreign currencies at December 31, 2014.

63

Item 8. Financial Statements and Supplementary Data

NEWFIELD EXPLORATION COMPANY
TABLE OF CONTENTS
CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY INFORMATION
 
 
Page

64

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and the Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), the management of our Company concluded that our internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that follows.
 
 
Lee K. Boothby
 
Lawrence S. Massaro
President and Chief Executive Officer
 
Executive Vice President and Chief Financial Officer

The Woodlands, Texas
February 24, 2015

65

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Newfield Exploration Company:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Newfield Exploration Company and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Houston, Texas
February 24, 2015


66

NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except share data)
 
 
December 31,
 
 
2014
 
2013
ASSETS
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
14

 
$
95

Restricted cash
 
—

 
90

Accounts receivable, net
 
405

 
474

Inventories
 
33

 
163

Derivative assets
 
431

 
—

Deferred taxes
 
—

 
22

Other current assets
 
57

 
57

Total current assets
 
940

 
901

Oil and gas properties — full cost method ($677 and $1,300 were excluded from amortization at
December 31, 2014 and 2013, respectively)
 
16,384

 
16,407

Less — accumulated depreciation, depletion and amortization
 
(8,152
)
 
(8,306
)
Total oil and gas properties, net
 
8,232

 
8,101

Other property and equipment, net
 
182

 
174

Derivative assets
 
190

 
26

Long-term investments
 
26

 
63

Deferred taxes
 
—

 
19

Other assets
 
28

 
37

Total assets
 
$
9,598

 
$
9,321

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
 
 
 
 
Accounts payable
 
$
32

 
$
76

Accrued liabilities
 
880

 
978

Deferred liabilities
 
—

 
90

Advances from joint owners
 
34

 
30

Asset retirement obligations
 
3

 
54

Derivative liabilities
 
8

 
62

Deferred taxes
 
144

 
—

Total current liabilities
 
1,101

 
1,290

Other liabilities
 
45

 
38

Long-term debt
 
2,892

 
3,694

Asset retirement obligations
 
183

 
201

Deferred taxes
 
1,484

 
1,142

Total long-term liabilities
 
4,604

 
5,075

Commitments and contingencies (Note 13)
 


 


Stockholders’ equity:
 
 
 
 
Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)
 
—

 
—

Common stock ($0.01 par value, 200,000,000 shares authorized at December 31, 2014 and 2013;
137,603,643 and 136,682,631 shares issued at December 31, 2014 and 2013, respectively)
 
1

 
1

Additional paid-in capital
 
1,576

 
1,539

Treasury stock (at cost, 275,069 and 460,914 shares at December 31, 2014 and 2013, respectively)
 
(10
)
 
(13
)
Accumulated other comprehensive gain (loss)
 
(1
)
 
2

Retained earnings
 
2,327

 
1,427

Total stockholders’ equity
 
3,893

 
2,956

Total liabilities and stockholders’ equity
 
$
9,598

 
$
9,321


The accompanying notes to consolidated financial statements are an integral part of this statement.

67

NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF OPERATIONS
(In millions, except per share data) 
 
 
Year Ended December 31,
 
 
2014

2013

2012
Oil, gas and NGL revenues
 
$
2,288

 
$
1,857

 
$
1,562

 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
Lease operating
 
321

 
284

 
306

Transportation and processing
 
174

 
137

 
107

Production and other taxes
 
111

 
79

 
85

Depreciation, depletion and amortization
 
870

 
685

 
704

General and administrative
 
222

 
219

 
211

Ceiling test impairment
 
—

 
—

 
1,488

Other
 
15

 
3

 
15

Total operating expenses
 
1,713

 
1,407

 
2,916

Income (loss) from operations
 
575

 
450

 
(1,354
)
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
Interest expense
 
(200
)
 
(205
)
 
(205
)
Capitalized interest
 
53

 
53

 
68

Commodity derivative income (expense)
 
610

 
(97
)
 
120

Other, net
 
(6
)
 
—

 
(3
)
Total other income (expense)
 
457

 
(249
)
 
(20
)
 
 
 
 
 
 
 
Income (loss) from continuing operations before income taxes
 
1,032

 
201

 
(1,374
)
 
 
 
 
 
 
 
Income tax provision (benefit):
 
 
 
 
 
 
Current
 
5

 
(2
)
 
16

Deferred
 
377

 
130

 
(468
)
Total income tax provision (benefit)
 
382

 
128

 
(452
)
Income (loss) from continuing operations
 
650

 
73

 
(922
)
Income (loss) from discontinued operations, net of tax
 
250

 
74

 
(262
)
Net income (loss)
 
$
900

 
$
147

 
$
(1,184
)
 
 
 
 
 
 
 
Earnings (loss) per share:
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
Income (loss) from continuing operations

$
4.76

 
$
0.39

 
$
(6.85
)
Income (loss) from discontinued operations

1.83

 
0.55

 
(1.95
)
Basic earnings (loss) per share
 
$
6.59

 
$
0.94

 
$
(8.80
)
Diluted:
 


 


 


Income (loss) from continuing operations
 
$
4.71

 
$
0.39

 
$
(6.85
)
Income (loss) from discontinued operations
 
1.81

 
0.55

 
(1.95
)
Diluted earnings (loss) per share
 
$
6.52

 
$
0.94

 
$
(8.80
)
 
 


 


 


Weighted-average number of shares outstanding for basic earnings
(loss) per share
 
137

 
135

 
135

 
 
 
 
 
 
 
Weighted-average number of shares outstanding for diluted earnings
(loss) per share
 
138

 
136

 
135




The accompanying notes to consolidated financial statements are an integral part of this statement.

68

NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In millions)
 
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Net income (loss)
 
$
900

 
$
147

 
$
(1,184
)
Other comprehensive income (loss):
 
 
 
 
 
 
Unrealized gain (loss) on investments, net of tax of $0 for the year ended December 31, 2014, ($3) for the year ended December 31, 2013, and ($1) for the year ended December 31, 2012
 
—

 
7

 
3

Unrealized gain (loss) on post-retirement benefits, net of tax of $2 for the year ended
   December 31, 2014, ($1) for the year ended December 31, 2013, and $0 for the year ended December 31, 2012
 
(3
)
 
2

 
—

Other comprehensive income (loss), net of tax
 
(3
)
 
9

 
3

Comprehensive income (loss)
 
$
897

 
$
156

 
$
(1,181
)







































The accompanying notes to consolidated financial statements are an integral part of this statement.

69

NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
 
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
 
 
Net income (loss)
 
$
900

 
$
147

 
$
(1,184
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
 
Depreciation, depletion and amortization
 
903

 
930

 
955

Deferred tax provision (benefit)
 
509

 
143

 
1

Stock-based compensation
 
28

 
43

 
35

Commodity derivative (income) expense
 
(610
)
 
97

 
(120
)
Cash receipts (payments) related to derivative contracts, net
 
(39
)
 
60

 
135

Gain on sale of Malaysia business
 
(373
)
 
—

 
—

Ceiling test impairment
 
—

 
—

 
1,488

Other, net
 
21

 
14

 
19

Changes in operating assets and liabilities:
 
 
 
 
 
 
(Increase) decrease in accounts receivable
 
47

 
(62
)
 
(70
)
(Increase) decrease in inventories
 
—

 
(11
)
 
(35
)
(Increase) decrease in other current assets
 
(30
)
 
12

 
5

(Increase) decrease in other assets
 
2

 
6

 
7

Increase (decrease) in accounts payable and accrued liabilities
 
21

 
74

 
(77
)
Increase (decrease) in advances from joint owners
 
5

 
(1
)
 
(14
)
Increase (decrease) in other liabilities
 
3

 
(7
)
 
2

Net cash provided by (used in) operating activities
 
1,387

 
1,445

 
1,147

Cash flows from investing activities:
 
 
 
 
 
 
Additions to oil and gas properties
 
(2,064
)
 
(1,987
)
 
(1,758
)
Acquisitions of oil and gas properties
 
(33
)
 
(72
)
 
(9
)
Proceeds from sales of oil and gas properties, net
 
620

 
36

 
630

Proceeds received from sale of Malaysia business, net
 
809

 
—

 
—

Additions to other property and equipment
 
(31
)
 
(36
)
 
(22
)
Redemptions of investments
 
39

 
1

 
—

Net cash provided by (used in) investing activities
 
(660
)
 
(2,058
)
 
(1,159
)
Cash flows from financing activities:
 
 
 
 
 
 
Proceeds from borrowings under credit arrangements
 
2,949

 
3,263

 
2,844

Repayments of borrowings under credit arrangements
 
(3,152
)
 
(2,614
)
 
(2,930
)
Proceeds from issuance of senior notes
 
—

 
—

 
1,000

Debt issue costs
 
—

 
(4
)
 
(10
)
Repayment of senior subordinated notes
 
(600
)
 
—

 
(875
)
Proceeds from issuances of common stock
 
6

 
1

 
2

Repurchase of preferred shares of subsidiary
 
—

 
(20
)
 
—

Purchases of treasury stock, net
 
(11
)
 
(6
)
 
(7
)
Net cash provided by (used in) financing activities
 
(808
)
 
620

 
24

Increase (decrease) in cash and cash equivalents
 
(81
)
 
7

 
12

Cash and cash equivalents, beginning of period
 
95

 
88

 
76

Cash and cash equivalents, end of period
 
$
14

 
$
95

 
$
88



The accompanying notes to consolidated financial statements are an integral part of this statement.

70

NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
 
 

Common Stock

Treasury Stock

Additional
Paid-in
Capital

Retained
Earnings

Accumulated Other Comprehensive Gain (Loss)

Total
Stockholders’
Equity
 

Shares

Amount

Shares

Amount

Balance, December 31, 2011

136.4


$
1


(1.7
)

$
(50
)

$
1,495


$
2,484


$
(10
)

$
3,920

Issuances of common stock

0.1


—






2






2

Stock-based compensation









46






46

Treasury stock, net





0.5


14


(21
)





(7
)
Net income (loss)











(1,184
)



(1,184
)
Other comprehensive income (loss), net of tax














3


3

Balance, December 31, 2012

136.5


1


(1.2
)

(36
)

1,522


1,300


(7
)

2,780

Issuances of common stock

0.2


—






1






1

Stock-based compensation









45






45

Treasury stock, net





0.7


23


(29
)





(6
)
Net income (loss)











147




147

Other comprehensive income (loss), net of tax














9


9

Repurchase of preferred shares of subsidiary
















(20
)




(20
)
Balance, December 31, 2013

136.7


1


(0.5
)

(13
)

1,539


1,427


2


2,956

Issuances of common stock

0.9


—






6






6

Stock-based compensation









45






45

Treasury stock, net





0.2


3


(14
)





(11
)
Net income (loss)











900




900

Other comprehensive income (loss), net of tax














(3
)

(3
)
Balance, December 31, 2014

137.6


$
1


(0.3
)

$
(10
)

$
1,576


$
2,327


$
(1
)

$
3,893






















The accompanying notes to consolidated financial statements are an integral part of this statement.

71

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.
Organization and Summary of Significant Accounting Policies:

Organization and Principles of Consolidation

We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). Our principal domestic areas of operation include the Mid-Continent, the Rocky Mountains and the onshore Gulf Coast regions of the United States. In addition, we have offshore oil developments in China.

Our consolidated financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and natural gas exploration and production ventures and partnerships in accordance with industry practice. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to “Newfield,” “we,” “us,” “our” or the “Company” are to Newfield Exploration Company and its subsidiaries.

Discontinued Operations

Our businesses in Malaysia and China were classified as held for sale in the second quarter of 2013. As of December 31, 2014, our China business is no longer held for sale, as we concluded the marketing process and were unable to sell at an acceptable price given the significant decrease in oil prices in the fourth quarter of 2014. Therefore, our China business is included in continuing operations for all periods in these financial statements. The results of our Malaysia operations are reflected separately as discontinued operations in the consolidated statement of operations on a line immediately after "Income (loss) from continuing operations." See Note 3, "Discontinued Operations," for additional disclosures, as well as information regarding the sale of our Malaysia business, which closed in February 2014. These financial statements and notes are inclusive of our Malaysia operations unless otherwise noted.

Risks and Uncertainties

As an independent oil and natural gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for oil, natural gas and NGLs. Historically, the energy markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas and NGL reserves that we can economically produce. It is possible for any of these effects to occur in the near term, given the recent decline in commodity pricing.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of our oil and gas properties. Actual results could differ significantly from these estimates. Our most significant estimates are associated with the quantities of proved oil, natural gas and NGL reserves, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool and the fair value of both our derivative positions and our stock-based compensation liability awards.

Reclassifications

Certain reclassifications have been made to prior years’ reported amounts in order to conform to the current year presentation. These reclassifications did not impact our net income (loss), stockholders’ equity or cash flows.

Revenue Recognition

Substantially all of our oil, natural gas and NGLs are sold at market-based prices to a variety of purchasers under short-term contracts (less than 12 months). We also have long-term contracts in the Uinta Basin at market-based prices, less a variable differential that becomes fixed below certain market price thresholds. We record revenue when we deliver our production to the

72

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

customer and collectability is reasonably assured. Revenues from the production of oil, natural gas and NGLs on properties in which we have joint ownership are recorded under the sales method. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of production. Should the Company’s excess sales exceed our share of estimated remaining recoverable reserves, a liability is recorded. Differences between sales and our entitled share of production are not significant.

Foreign Currency

The functional currency for our foreign operations is the U.S. dollar. Gains and losses incurred on transactions in a currency other than a country’s functional currency are recorded under the caption “Other income (expense) — Other, net” on our consolidated statement of operations.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with a maturity of three months or less when acquired and are stated at cost, which approximates fair value. We invest cash in excess of near-term capital and operating requirements in U.S. Treasury Notes, Eurodollar time deposits and money market funds, which are classified as cash and cash equivalents on our consolidated balance sheet.

Restricted Cash and Deferred Liabilities

Restricted cash and the associated deferred liability on our consolidated balance sheet at December 31, 2013 represent a deposit received in the fourth quarter of 2013 related to the sale of our Malaysia business. Amounts were contractually restricted until the transaction closed in February 2014. See Note 3, "Discontinued Operations," for further discussion about the close of the sale of the Malaysia business.

Investments

Investments consist of debt and equity securities, a majority of which are classified as “available-for-sale” and stated at fair value. Accordingly, unrealized gains and losses and the related deferred income tax effects are excluded from earnings and reported in other comprehensive income within our consolidated statement of stockholders' equity. Realized gains or losses are computed based on specific identification of the securities sold. We regularly assess our investments for impairment and consider any impairment to be other than temporary if we intend to sell the security, it is more likely than not that we will be required to sell the security or we do not expect to recover our cost of the security.

Allowance for Doubtful Accounts

We routinely assess material trade and other receivables to determine their collectability. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, our oil and gas receivables are collected within 45 to 60 days of production. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated.

Inventories

Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations and oil produced but not sold in our international operations. Tubular goods and well equipment inventories are carried at the lower of cost or market. During 2014, we wrote down obsolete inventory across all three of our domestic regions. At December 31, 2012, we wrote down subsea wellhead inventory that was not included in the sale of our Gulf of Mexico assets. The writedowns of $9 million in 2014 and $8 million in 2012 are included in “Operating expenses — Other” on our consolidated statement of operations.

Substantially all of the crude oil from our offshore operations in China is produced into floating storage facilities and “lifted” and sold periodically as barge quantities are accumulated. At December 31, 2014 and 2013, the crude oil inventory from our China operations consisted of approximately 240,000 and 23,000 barrels of crude oil valued at cost of approximately

73

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$8 million and $1 million, respectively, and is included under the caption "Inventories" on our consolidated balance sheet. Cost for purposes of the carrying value of oil inventory is the sum of related production costs and depletion expense. See Note 3, "Discontinued Operations" for details on our Malaysia crude oil inventory.

Oil and Gas Properties

We use the full cost method of accounting for our oil and gas producing activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties, including salaries, benefits, interest and other internal costs directly attributable to these activities, are capitalized into cost centers that are established on a country-by-country basis. We capitalized approximately $199 million, $198 million and $191 million of interest and direct internal costs in 2014, 2013 and 2012, respectively.

Proceeds from the sale of oil and gas properties are applied to reduce the costs in the applicable cost center unless the reduction would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. During the first quarter of 2014, we sold our Malaysia business, which constituted the entire full cost pool for Malaysia. See Note 3, "Discontinued Operations," for further discussion.

Capitalized costs and estimated future development costs are amortized using a unit-of-production method based on proved reserves associated with the applicable cost center. For each cost center, the net capitalized costs of oil and gas properties are limited to the lower of the unamortized cost or the cost center ceiling. A particular cost center ceiling is equal to the sum of:

•
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.

If net capitalized costs of oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. If required, a ceiling test writedown reduces earnings and stockholders’ equity in the period of occurrence and, holding other factors constant, results in lower depreciation, depletion and amortization expense in future periods.

The risk that we will be required to writedown the carrying value of our oil and gas properties increases when oil, natural gas and NGL prices decrease significantly for a prolonged period of time or if we have substantial downward revisions in our estimated proved reserves. At December 31, 2014, the ceiling value of our reserves was calculated based upon SEC pricing of $4.35 per MMBtu for natural gas and $94.98 per barrel for oil. Using these prices, our ceilings for the U.S. and China exceeded the net capitalized costs of oil and gas properties by approximately $400 million and $150 million, respectively, net of tax, and as such, no ceiling test writedown was required.

The continued decline of SEC pricing for oil and natural gas reserves since December 31, 2014 will likely result in a ceiling test writedown in the first quarter of 2015.

At December 31, 2013, the ceiling value of our reserves was calculated based upon SEC pricing of $3.67 per MMBtu for natural gas and $96.82 per barrel for oil. Using these prices, the cost center ceilings with respect to our domestic and China full cost pools exceeded the net capitalized costs. As such, no ceiling test writedowns were required at December 31, 2013.

At December 31, 2012, the ceiling value of our reserves was calculated based upon SEC pricing of $2.76 per MMBtu for natural gas and $94.84 per barrel for oil. Using these prices, the unamortized net capitalized costs of our domestic oil and gas properties exceeded the ceiling amount by approximately $1.5 billion ($948 million, after tax). No ceiling test writedown was required for the China full cost pool at December 31, 2012.


74

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

See Note 4, “Oil and Gas Assets,” for a detailed discussion regarding our oil and gas asset acquisitions and sales transactions during 2014, 2013 and 2012.

Other Property and Equipment

Furniture, fixtures and equipment are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, which range from three to seven years. Gathering systems and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives of 25 years.

Accounting for Asset Retirement Obligations

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the ARO is incurred. Settlements include payments made to satisfy the AROs, as well as transfer of the AROs to purchasers of our divested properties.

In general, the amount of an ARO and the costs capitalized will equal the estimated future costs to satisfy the abandonment obligation assuming normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds, and the original capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. Both the accretion and the depreciation are included in depreciation, depletion and amortization expense on our consolidated statement of operations.

The change in our ARO for continuing operations for each of the three years ended December 31, is set forth below:
 
 
 
2014
 
2013
 
2012
 
 
(In millions)
Balance at January 1
 
$
122

 
$
102

 
$
108

Accretion expense
 
8

 
8

 
8

Additions(1)
 
58

 
12

 
20

Revisions
 
16

 
8

 
12

Settlements(2)
 
(18
)
 
(8
)
 
(46
)
Balance at December 31
 
186

 
122

 
102

Less: Current portion of ARO at December 31
 
(3
)
 
(5
)
 
(5
)
Total long-term ARO at December 31
 
$
183

 
$
117

 
$
97

_________________
(1)
For the year ended December 31, 2014, additions include $28 million for our Pearl development in offshore China and $30 million for abandonment obligations in our domestic business.
(2)
For the year ended December 31, 2014, settlements include $10 million related to the sale of our Granite Wash assets. For the year ended December 31, 2012, settlements include $28 million related to the sale of our Gulf of Mexico assets. See Note 4, “Oil and Gas Assets.”

Contingencies

We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 13, “Commitments and Contingencies,” for a more detailed discussion regarding our contingencies. 




75

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Environmental Matters

Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.

Income Taxes

We use the liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are determined by applying tax regulations existing at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

As of December 31, 2014, we did not have a liability for uncertain tax positions, and as such, we did not accrue related interest or penalties. The tax years 2011-2014 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

Stock-Based Compensation

We apply a fair value-based method of accounting for stock-based compensation which requires recognition in the financial statements of the cost of services received in exchange for awards of equity instruments based on the grant date fair value of those awards. For equity awards, compensation expense is based on the fair value on the grant or modification date and is recognized in our financial statements over the vesting period. We utilize the Black-Scholes option-pricing model to measure the fair value of stock options and a Monte Carlo lattice-based model for our performance and market-based restricted stock and restricted stock units. We also have cash-settled restricted stock units as well as a Stockholder Value Appreciation Program that are accounted for under the liability method which requires us to recognize the fair value of each award based on the underlying share price at the end of each period. See Note 11, “Stock-Based Compensation,” for a full discussion of our stock-based compensation.

Concentration of Credit Risk

We operate a substantial portion of our oil and gas properties. As the operator of a property, we make full payment for costs associated with the property and seek reimbursement from the other working interest owners in the property for their share of those costs. Our joint interest owners consist primarily of independent oil and gas producers. If the oil and gas exploration and production industry in general was adversely affected, the ability of our joint interest partners to reimburse us could be adversely affected.

The purchasers of our oil, gas and NGL production consist primarily of independent marketers, major oil and gas companies, refiners and gas pipeline companies. We perform credit evaluations of the purchasers of our production and monitor their financial condition on an ongoing basis. Based on our evaluations and monitoring, we obtain cash escrows, letters of credit or parental guarantees from some purchasers.

All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating. We monitor the credit ratings of our hedging counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in hedging transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes. At December 31, 2014, ten of our 16 counterparties accounted for approximately 85% of our contracted volumes, with no single counterparty accounting for more than 15%. Approximately 40% of our volumes subject to derivative instruments are with lenders under our credit facility. Our credit facility, senior notes, senior subordinated notes

76

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and substantially all of our derivative instruments contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

Major Customers

Tesoro Corporation and Sunoco Logistics Partners Operations GP LLC accounted for 12% and 10%, respectively, of our total revenues in 2014. During 2013, Sunoco Logistics Partners Operations GP LLC, Royal Dutch Shell plc and Tesoro Corporation accounted for 13%, 12%, and 11%, respectively, of our total revenues. During 2012, sales of our oil and gas production to Royal Dutch Shell plc, Tesoro Corporation and Big West Oil LLC accounted for 14%, 14% and 10%, respectively, of our total revenues. We believe that the loss of any of our major customers would not have a material adverse effect on us because alternative purchasers are available.

Derivative Financial Instruments

Our derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. While we utilize our derivative instruments to manage the price risk attributable to our expected oil and gas production, we have elected not to designate our derivative instruments as accounting hedges under the accounting guidance.

The related cash flow impact of our derivative activities are reflected as cash flows from operating activities unless they are determined to have a significant financing element at inception, in which case they are classified within financing activities. See Note 5, “Derivative Financial Instruments,” for a more detailed discussion of our derivative activities.

Offsetting Assets and Liabilities

Our derivative financial instruments are subject to master netting arrangements and are reflected on our consolidated balance sheet accordingly. See Note 5, "Derivative Financial Instruments," for details regarding the gross amounts, as well as the impact of our netting arrangements on our net derivative position. We only offset assets and liabilities in relation to our derivative financial instruments.

Accumulated Other Comprehensive Income

At December 31, 2012, accumulated other comprehensive income (“AOCI”) included unrealized losses related to auction rate securities that were deemed to be temporary as the Company had the intent and ability to hold the securities to maturity. As of December 31, 2013, the Company changed its intention and considered plans to sell the securities. As a result, the losses previously accumulated in AOCI related to these securities were transferred and recognized in the consolidated statement of operations for the year ended December 31, 2013. During the first quarter of 2014, all auction rate securities were sold for $39 million. The change in AOCI for the indicated periods is set forth below:
 
 
Unrealized Gains / (Losses) in
Accumulated Other Comprehensive Income
 
 
Available-for-Sale Securities
 
Post-Retirement Benefits
 
Total
 
 
(In millions, net of tax)
Balance at January 1, 2012
 
$
(9
)
 
$
(1
)
 
$
(10
)
Current period other comprehensive income (loss)
 
3

 
—

 
3

Balance at December 31, 2012
 
(6
)
 
(1
)
 
(7
)
Other comprehensive income before reclassifications
 
3

 
2

 
5

Amounts reclassified from accumulated other comprehensive income
 
4

 
—

 
4

Net current period other comprehensive income (loss)
 
7

 
2

 
9

Balance at December 31, 2013
 
1

 
1

 
2

Current period other comprehensive income (loss)
 
—

 
(3
)
 
(3
)
Balance at December 31, 2014
 
$
1

 
$
(2
)
 
$
(1
)

77

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


New Accounting Requirements

In August 2014, the FASB issued guidance regarding disclosures of uncertainties about an entity's ability to continue as a going concern. The guidance applies prospectively to all entities, requiring management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern and disclose certain information when substantial doubt is raised. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We do not expect this guidance to impact our Company.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We are currently evaluating the impact of this guidance on our financial statements.

In April 2014, the FASB issued guidance regarding the reporting of discontinued operations. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect this guidance to impact our Company.


2.
Earnings Per Share:

Basic earnings per share (EPS) is calculated by dividing net income, less any applicable adjustments, (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock and restricted stock units) outstanding during the period (the denominator). Diluted EPS incorporates the dilutive impact of outstanding stock options and unvested restricted stock and restricted stock units (using the treasury stock method). Under the treasury stock method, the amount the employee must pay for exercising stock options, the amount of unrecognized compensation expense related to unvested stock-based compensation grants and the amount of excess tax benefits that would be recorded when the award becomes deductible are assumed to be used to repurchase shares. See Note 11, “Stock-Based Compensation.”

The following is the calculation of basic and diluted weighted-average shares outstanding and EPS for the indicated years: 

78

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 
2014
 
2013
 
2012
 
 
(In millions, except per share data)
Income (numerator):
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
650

 
$
73

 
$
(922
)
Income (loss) from discontinued operations, net of tax
 
250

 
74

 
(262
)
Net income (loss)
 
900

 
147

 
(1,184
)
Repurchase of preferred shares of subsidiary(3)
 
—

 
(20
)
 
—

Net income (loss) attributable to common stockholders
 
$
900

 
$
127

 
$
(1,184
)
 
 
 
 
 
 
 
Weighted-average shares (denominator):
 
 
 
 
 
 
Weighted-average shares — basic
 
137

 
135

 
135

Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period(1)(2)
 
1

 
1

 
—

Weighted-average shares — diluted
 
138

 
136

 
135

 
 
 
 
 
 
 
Earnings (loss) per share:
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
Income (loss) from continuing operations before preferred share repurchase
 
$
4.76

 
$
0.54

 
$
(6.85
)
Repurchase of preferred shares of subsidiary(3)
 
—

 
(0.15
)
 
—

Income (loss) from continuing operations
 
4.76

 
0.39

 
(6.85
)
Income (loss) from discontinued operations
 
1.83

 
0.55

 
(1.95
)
Basic earnings (loss) per share
 
$
6.59

 
$
0.94

 
$
(8.80
)
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
Income (loss) from continuing operations before preferred share repurchase
 
$
4.71

 
$
0.54

 
$
(6.85
)
Repurchase of preferred shares of subsidiary(3)
 
—

 
(0.15
)
 
—

Income (loss) from continuing operations
 
4.71

 
0.39

 
(6.85
)
Income (loss) from discontinued operations
 
1.81

 
0.55

 
(1.95
)
Diluted earnings (loss) per share
 
$
6.52

 
$
0.94

 
$
(8.80
)
_________________
(1)
Excludes 1.1 million and 4.0 million shares of unvested restricted stock or restricted stock units and stock options for the years ended December 31, 2014 and 2013, respectively, because including the effect would have been anti-dilutive.
(2)
The effect of unvested restricted stock or restricted stock units and stock options has not been included in the calculation of shares outstanding for diluted EPS for the year ended December 31, 2012, as their effect would have been anti-dilutive. Had we recognized income from continuing operations for that year, incremental shares attributable to the assumed vesting of unvested restricted stock and restricted stock units and the assumed exercise of outstanding stock options would have increased diluted weighted-averages shares outstanding by 0.7 million shares for the year ended December 31, 2012.
(3)
The numerator includes an adjustment of $20 million related to the repurchase of preferred shares of a now wholly-owned subsidiary, which reduces net income (loss) for purposes of earnings per share for the year ended December 31, 2013. The subsidiary is part of our continuing operations. See Note 16, "Related Party Transaction," for additional information.


3. Discontinued Operations:

In 2013, we met the criteria to classify our Malaysia business as held-for-sale and discontinued operations. In February 2014, Newfield International Holdings Inc., a wholly-owned subsidiary of the Company, closed the sale of our Malaysia business to SapuraKencana Petroleum Berhad (SapuraKencana), a Malaysian public company, for $898 million. As a result of

79

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the sale, we recorded a gain in the first quarter of 2014 of approximately $388 million ($252 million, after tax). As of the date of this report, the final post-close settlement is pending due to a dispute with the purchaser that arose subsequent to closing and could possibly go to arbitration. In the fourth quarter of 2014, we recorded an allowance against a receivable from SapuraKencana and reduced the previously recognized gain by $15 million ($10 million, after tax) due to uncertainty associated with collectability.

Results of Discontinued Operations
 
 
Year Ended December 31,
 
 
2014
 
2013

2012
 
 
(In millions)
Oil and gas revenues (1)
 
$
90

 
$
823

 
$
1,005

Operating expenses
 
69

 
652

 
618

    Income from discontinued operations
 
21

 
171

 
387

Other income (expense)
 
—

 
4

 
(1
)
Gain on sale of Malaysia business
 
373

 
—

 
—

Income from discontinued operations before income taxes
 
394

 
175

 
386

Income tax provision (benefit):
 


 


 


    Current
 
12

 
88

 
179

    Deferred
 
132

 
13

 
469

    Total income tax provision (benefit)
 
144

 
101

 
648

Income (loss) from discontinued operations, net of tax
 
$
250

 
$
74

 
$
(262
)
________________
(1) Certain payments to foreign governments made on our behalf that are part of the revenue process are recorded as a reduction of the related oil and gas revenues.


80

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income Taxes

Historically, our effective tax rate in Malaysia was approximately 38%. As a result of our December 2012 decision to repatriate earnings from our international operations, we experienced higher international effective tax rates due to these earnings being taxed both in the U.S. and the local country. For the year ended 2014, our effective tax rate in Malaysia was 37% as the majority of our income from discontinued operations resulted from the gain on the sale of our Malaysia business, which was only taxable in the U.S. The effective tax rate for our discontinued operations for the years ended 2013 and 2012 was 58% and 168%, respectively, due to our international earnings being taxed both in the U.S and the local country.

Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations


December 31,


2013


(In millions)
Current assets:


Cash and cash equivalents

$
55

Accounts receivable

142

Inventories

121

  Other current assets

29

Total current assets

347

Noncurrent assets:



 Oil and gas properties, net of accumulated depreciation, depletion and amortization of $1,009 as of December 31, 2013

547

Deferred taxes

19

  Other assets

3

Total noncurrent assets

569

Total assets

$
916





Current liabilities:



Accounts payable

$
34

  Accrued liabilities

185

Asset retirement obligations
 
49

  Other current liabilities

18

Total current liabilities

286
Noncurrent liabilities:



  Asset retirement obligations

84

Deferred taxes

29

  Other liabilities

11

Total noncurrent liabilities

124

Total liabilities

$
410


Inventories

At December 31, 2013, the crude oil inventory from our Malaysia operations consisted of approximately 1.1 million barrels of crude oil valued at cost of $89 million and is included in the "Inventories" line item in the preceding table and in our consolidated balance sheet. Cost for purposes of the carrying value of oil inventory is the sum of production costs and depletion expense.



81

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil and Gas Properties

At December 31, 2013, we performed a fair value assessment of our discontinued operations, noting no indication of impairment based on the carrying value.

During 2012, when our Malaysia business was reported as continuing operations, we performed a ceiling test for the full cost pool. The ceiling value of our reserves was calculated based upon SEC pricing of $2.76 per MMBtu for natural gas and $94.84 per barrel for oil. Using these prices, the cost center ceiling with respect to our Malaysia full cost pool exceeded the net capitalized costs of the respective cost center at December 31, 2012 and as such, no ceiling test writedown was required.

The change in our ARO for our discontinued operations for each of the three years ended December 31, is set forth below: 
 
 
2014
 
2013
 
2012
 
 
(In millions)
Balance at January 1
 
$
133

 
$
40

 
$
37

Accretion expense
 
1

 
3

 
3

Additions
 
—

 
4

 
4

Revisions
 
—

 
101

 
—

Settlements (1)
 
(134
)
 
(15
)
 
(4
)
Balance at December 31
 
—

 
133

 
40

Less: Current portion of ARO at December 31
 
—

 
(49
)
 
(5
)
Total long-term ARO at December 31
 
$
—

 
$
84

 
$
35

________________
(1) Obligations reduced as a result of the sale of our Malaysia business in February 2014.


4.
Oil and Gas Assets:

Property and Equipment

Property and equipment consisted of the following at December 31: 
 
 
2014
 
2013
 
 
(In millions)
Oil and gas properties:
 
 
 
 
Subject to amortization
 
$
15,707

 
$
15,107

Not subject to amortization
 
677

 
1,300

Gross oil and gas properties
 
16,384

 
16,407

Accumulated depreciation, depletion and amortization
 
(8,152
)
 
(8,306
)
Net oil and gas properties
 
$
8,232

 
$
8,101

Other property and equipment:
 


 


Furniture, fixtures and equipment
 
$
144

 
$
139

Gathering systems and equipment
 
114

 
104

Accumulated depreciation and amortization
 
(76
)
 
(69
)
Net other property and equipment
 
$
182

 
$
174


Oil and gas properties not subject to amortization represent investments in unproved properties and major development projects in which we own an interest. These unproved property costs include unevaluated leasehold acreage, geological and geophysical data costs associated with leasehold or drilling interests, costs associated with wells in progress at year-end and capitalized internal costs. We exclude these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. Unproved property costs are grouped by major prospect area where individual property

82

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

costs are not significant and are assessed individually when individual costs are significant. Costs associated with wells in progress are transferred to the amortization base upon the determination of whether proved reserves can be assigned to the properties, which is generally based on drilling results. All other costs excluded from the amortization base are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the amortization base or a charge is made against earnings for international operations if a reserve base has not yet been established.

During the fourth quarter of 2014, crude oil and natural gas prices declined to price levels that are likely to change our future development plans in certain operating areas of our domestic business. Accordingly, we transferred approximately $760 million of costs that were previously withheld from the full cost pool into the full cost pool amortization base.

Oil and gas properties not subject to amortization as of December 31, 2014, consisted of the following:

 
 
Costs Incurred In
 
 
 
 
2014
 
2013
 
2012
 
2011 and Prior
 
Total
 
 
(In millions)
Acquisition costs
 
$
185

 
$
159

 
$
41

 
$
84

 
$
469

Exploration costs
 
111

 
—

 
—

 
3

 
114

Fee mineral interests
 
—

 
1

 
—

 
23

 
24

Capitalized interest
 
53

 
17

 
—

 
—

 
70

Total oil and gas properties not subject to amortization
 
$
349

 
$
177

 
$
41

 
$
110

 
$
677


Granite Wash Asset Sale

In September 2014, we closed on the sale of our Granite Wash assets, located primarily in Texas, for approximately $588 million, subject to customary post-closing purchase price adjustments. The sale of our Granite Wash assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Granite Wash operations through the date of sale.

Gulf of Mexico Asset Sale

In October 2012, we closed the sale of our remaining assets in the Gulf of Mexico to W&T Offshore, Inc. for approximately $208 million, subject to customary post-closing adjustments. The sale of our remaining assets in the Gulf of Mexico did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Gulf of Mexico operations through the date of sale.

Other Asset Acquisitions and Sales

During 2014, 2013 and 2012, we acquired various other oil and gas properties for approximately $33 million, $72 million and $9 million, respectively, and sold certain other oil and gas properties for proceeds of approximately $69 million, $36 million and $422 million, respectively. The cash flows and results of operations for the assets included in a sale are included in our consolidated financial statements up to the date of sale. All of the proceeds associated with our asset sales were recorded as adjustments to our domestic full cost pool.


83

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.
Derivative Financial Instruments:

Commodity Derivative Instruments

We utilize the following derivative strategies, which consist of either a single derivative instrument or a combination of instruments, to manage the variability in cash flows associated with the forecasted sale of our domestic oil and natural gas production.

•
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.
•
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.
•
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.
•
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.
•
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. 

While the use of these derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements. For discussion of the accounting policies associated with our derivative financial instruments (including the offsetting of derivative assets and liabilities), see Note 1, "Organization and Summary of Significant Accounting Policies."
     
Our oil and gas derivative contracts are settled based upon reported prices on the NYMEX. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, estimated volatility, non-performance risk adjustments using credit default swaps, interest rates and time to maturity. The calculation of the fair value of options requires the use of an option-pricing model. See Note 8, “Fair Value Measurements.”


84

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2014, we had outstanding derivative positions as set forth in the tables below.

Natural Gas
 
Period and Type of Instrument
 
 
 
NYMEX Contract Price Per MMBtu
 
 
 
 
 
 
 
 
 
Collars
 
 
 
Volume in
MMMBtus
 
Swaps
(Weighted
Average)
 
Sold Puts(Weighted
Average)
 
Floors(Weighted
Average)
 
Ceilings(Weighted
Average)
 
Estimated
Fair Value
Asset
(Liability)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
 
2015:
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
49,275

 
$
4.28

 
$
—

 
$
—

 
$
—

 
$
62

 
Collars
 
38,325

 
—

 
—

 
3.93

 
4.74

 
36

 
2016:
 
 
 
 
 
 
 
 
 
 
 
 
 
Swaptions (1)
 
—

 
4.10

 
—

 
—

 
—

 
(2
)
 
Collars
 
10,980

 
—

 
—

 
4.00

 
4.54

 
7

 
Total
 
 
 
 
 
 
 
 
 
 
 
$
103

_________________
(1)
During the fourth quarter of 2014, we sold natural gas swaption contracts that, if exercised on their expiration date in the second quarter of 2015, would protect 14,640 MMMBtus of calendar-year 2016 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at $4.10/MMBtu for calendar-year 2016.


85

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Crude Oil
 
 
 
 
NYMEX Contract Price Per Bbl
 
 
 
 
 
 
 
 
 
 
Collars
 
Estimated Fair Value
Asset (Liability)
Period and Type of Instrument
 
Volume in MBbls
 
Swaps
(Weighted Average)
 
Sold Puts
(Weighted Average) (1)
 
Floors
(Weighted Average)
 
Ceilings
(Weighted Average)
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
2015:
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-price swaps
 
2,275

 
$
90.20

 
$
—

 
$
—

 
$
—

 
$
78

  Fixed-price swaps with sold puts:
 
15,019

 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
90.02

 
—

 
—

 
—

 
495

Sold puts
 
 
 
—

 
71.67

 
—

 
—

 
(258
)
  Collars with sold puts:
 
730

 
 
 
 
 
 
 
 
 
 
Collars
 
 
 
—

 
—

 
90.00

 
104.00

 
25

Sold puts
 
 
 
—

 
75.00

 
—

 
—

 
(15
)
2016:
 
 

 
 

 
 

 
 

 
 

 
 

  Fixed-price swaps with sold puts:
 
10,060

 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
89.98

 
—

 
—

 
—

 
266

Sold puts
 
 
 
—

 
74.14

 
—

 
—

 
(174
)
  Collars with sold puts:
 
6,220

 
 
 
 
 
 
 
 
 
 
Collars
 
 
 
—

 
—

 
90.00

 
96.15

 
170

Sold puts
 
 
 
—

 
75.00

 
—

 
—

 
(112
)
  Swaptions (2)
 
—

 
91.00

 
—

 
—

 
—

 
—

2017:
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-price swaps with sold puts:
 
4,468

 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
88.37

 
—

 
—

 
—

 
93

Sold puts
 
 
 
—

 
73.28

 
—

 
—

 
(72
)
  Collars with sold puts:
 
2,080

 
 
 
 
 
 
 
 
 
 
Collars
 
 
 
—

 
—

 
90.00

 
95.59

 
50

Sold puts
 
 
 
—

 
75.00

 
—

 
—

 
(36
)
Total
 
$
510

_________________
(1)
If the market prices remain below our sold puts at contract settlement, we will receive the market price plus the following associated with our production:

•
the difference between our floors and our sold puts for collars with sold puts; or
•
the difference between our swaps and our sold puts for fixed-price swaps with sold puts.

(2)
During the third quarter of 2014, we sold crude oil swaption contracts that, if exercised on their expiration date in the first quarter of 2015, would protect 732 MBbls of calendar-year 2016 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at $91.00/Bbl for calendar-year 2016.

Additional Disclosures about Derivative Instruments

We had derivative financial instruments recorded in our consolidated balance sheet as assets (liabilities) at their respective estimated fair value, as set forth below. 

86

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 
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, 2014
 
(In millions)
 
(In millions)
Natural gas positions
 
$
105

 
$
(2
)
 
$
99

 
$
4

 
$
(2
)
 
$
2

 
$
—

 
$
—

Oil positions
 
1,115

 
(597
)
 
332

 
186

 
(605
)
 
597

 
(8
)
 
—

Total
 
$
1,220

 
$
(599
)
 
$
431

 
$
190

 
$
(607
)
 
$
599

 
$
(8
)
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Natural gas positions
 
$
11

 
$
(2
)
 
$
—

 
$
9

 
$
(22
)
 
$
2

 
$
(20
)
 
$
—

Oil positions
 
26

 
(9
)
 
—

 
17

 
(51
)
 
9

 
(42
)
 
—

Total
 
$
37

 
$
(11
)
 
$
—

 
$
26

 
$
(73
)
 
$
11

 
$
(62
)
 
$
—


The amount of gain (loss) recognized in “Commodity derivative income (expense)” in our consolidated statement of operations related to our derivative financial instruments follows: 

 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(In millions)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
Realized gain (loss) on natural gas positions
 
$
(36
)
 
$
66

 
$
144

Realized gain (loss) on oil positions
 
(3
)
 
(6
)
 
1

Realized gain (loss) on basis positions
 
—

 
—

 
(10
)
Total realized gain (loss)
 
(39
)
 
60

 
135

Unrealized gain (loss) on natural gas positions
 
114

 
(81
)
 
(124
)
Unrealized gain (loss) on oil positions
 
535

 
(76
)
 
99

Unrealized gain (loss) on basis positions
 
—

 
—

 
10

Total unrealized gain (loss)
 
649

 
(157
)
 
(15
)
Total gain (loss)
 
$
610

 
$
(97
)
 
$
120



6. Accounts Receivable:

Accounts receivable consisted of the following at December 31:
 
 
2014
 
2013
 
 
(In millions)
Revenue
 
$
155

 
$
294

Joint interest
 
230

 
156

Other
 
36

 
25

Reserve for doubtful accounts
 
(16
)
 
(1
)
Total accounts receivable, net
 
$
405

 
$
474


Reserve for doubtful accounts at December 31, 2014 includes an allowance for $15 million related to discontinued operations. See Note 3, "Discontinued Operations."
 


87

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7. Accrued Liabilities:

Accrued liabilities consisted of the following at December 31:
 
 
 
2014
 
2013
 
 
(In millions)
Revenue payable
 
$
197

 
$
175

Accrued capital costs
 
441

 
458

Accrued lease operating expenses
 
47

 
71

Employee incentive expense
 
62

 
64

Accrued interest on debt
 
67

 
72

Taxes payable
 
32

 
93

Other
 
34

 
45

Total accrued liabilities
 
$
880

 
$
978



8.
Fair Value Measurements:

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

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 certain investments.
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). Level 3 instruments primarily include derivative instruments, such as commodity options (i.e., price collars, sold puts or swaptions) and other financial investments.
•
Our valuation models for derivative contracts are primarily industry-standard models (i.e., Black-Scholes) that consider various inputs including: (a) forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments.

•
Our valuation model for the Stockholder Value Appreciation Program (SVAP) is a Monte Carlo simulation that is based on a probability model and considers various inputs including: (a) the measurement date stock price, (b) time value and (c) historical and implied volatility. See Note 11, “Stock-Based Compensation,” for a description of the SVAP.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy.


88

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Recurring Fair Value Measurements

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.
 
 
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, 2013:
 
 
 
 
 
 
 
 
Money market fund investments
 
$
2

 
$
—

 
$
—

 
$
2

Deferred compensation plan assets
 
8

 
—

 
—

 
8

Investments available-for-sale:
 
 
 
 
 
 
 
 
Equity securities
 
8

 
—

 
—

 
8

Auction rate securities
 
—

 
—

 
39

 
39

Oil and gas derivative swap contracts
 
—

 
(28
)
 
—

 
(28
)
Oil and gas derivative option and swaption contracts
 
—

 
—

 
(8
)
 
(8
)
Stock-based compensation liability awards
 
(11
)
 
—

 
(5
)
 
(16
)
Total
 
$
7

 
$
(28
)
 
$
26

 
$
5

As of December 31, 2014:
 
 
 
 
 
 
 
 
Money market fund investments
 
$
1

 
$
—

 
$
—

 
$
1

Deferred compensation plan assets
 
9

 
—

 
—

 
9

Equity securities available-for-sale
 
10

 
—

 
—

 
10

Oil and gas derivative swap contracts
 
—

 
994

 
—

 
994

Oil and gas derivative option and swaption contracts
 
—

 
—

 
(381
)
 
(381
)
Stock-based compensation liability awards
 
(12
)
 
—

 
(3
)
 
(15
)
Total
 
$
8

 
$
994

 
$
(384
)
 
$
618


The determination of the fair values above incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), if any. We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties.

As of December 31, 2013, we held $39 million of auction rate securities, which were classified as a Level 3 fair value measurement. During the first quarter of 2014, all auction rate securities were sold for $39 million.



89

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Level 3 Fair Value Measurements

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods. 
 
 
Investments
 
Derivatives
 
Stock-Based Compensation
 
Total
 
 
(In millions)
Balance at January 1, 2012
 
$
32

 
$
71

 
$
—

 
$
103

Realized or unrealized gains (losses):
 

 

 

 

Included in earnings
 
—

 
135

 
—

 
135

Included in other comprehensive income (loss)
 
4

 
—

 
—

 
4

Purchases, issuances, sales and settlements:
 

 

 

 

Settlements
 
—

 
(91
)
 
—

 
(91
)
Transfers in to Level 3
 
—

 
—

 
—

 
—

Transfers out of Level 3
 
—

 
—

 
—

 
—

 Balance at December 31, 2012
 
$
36

 
$
115

 
$
—

 
$
151

Change in unrealized gains or losses included in earnings relating to
Level 3 instruments still held at December 31, 2012
 
$
—

 
$
82

 
$
—

 
$
82

Balance at January 1, 2013
 
$
36

 
$
115

 
$
—

 
$
151

Realized or unrealized gains (losses):
 

 

 

 

Included in earnings
 
(6
)
 
(66
)
 
(18
)
 
(90
)
Included in other comprehensive income (loss)
 
10

 
—

 
—

 
10

Purchases, issuances, sales and settlements:
 

 

 

 

Settlements
 
(1
)
 
(57
)
 
13

 
(45
)
Transfers in to Level 3
 
—

 
—

 
—

 
—

Transfers out of Level 3
 
—

 
—

 
—

 
—

Balance at December 31, 2013
 
$
39

 
$
(8
)
 
$
(5
)
 
$
26

Change in unrealized gains or losses included in earnings relating to
Level 3 instruments still held at December 31, 2013
 
$
(6
)
 
$
(10
)
 
$
—

 
$
(16
)
Balance at January 1, 2014
 
$
39

 
$
(8
)
 
$
(5
)
 
$
26

Realized or unrealized gains (losses):
 

 

 

 

Included in earnings
 
—

 
(381
)
 
(38
)
 
(419
)
Included in other comprehensive income (loss)
 
—

 
—

 
—

 
—

Purchases, issuances, sales and settlements:
 

 

 

 

Sales
 
(39
)
 
—

 
—

 
(39
)
Settlements
 
—

 
5

 
40

 
45

Transfers in to Level 3
 
—

 
—

 
—

 
—

Transfers out of Level 3(1)
 
—

 
3

 
—

 
3

Balance at December 31, 2014
 
$
—

 
$
(381
)
 
$
(3
)
 
$
(384
)
Change in unrealized gains or losses included in earnings relating to
Level 3 instruments still held at December 31, 2014
 
$
—

 
$
(375
)
 
$
2

 
$
(373
)
________
(1)
During the second quarter of 2014, we transferred $3 million of derivative option contracts out of the Level 3 hierarchy. The transfer was a result of our Level 3 swaptions being exercised by the counterparties as swaps on May 30, 2014.




90

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

Investments.   As of December 31, 2013, we held $39 million of auction rate securities maturing beginning in 2033 that were classified as a Level 3 fair value measurement. This amount reflected an other than temporary decrease in the fair value of these investments since the time of purchase of $6 million ($4 million net of tax) recorded in 2013 under the caption "Other income (expense) — Other, net" on our consolidated statement of operations as a result of our 2013 decision to liquidate our auction rate investments. During the first quarter of 2014, all auction rate securities were sold for $39 million.

Derivatives.   Our valuation models for Level 3 derivative option contracts are primarily industry-standard models that consider various factors, including certain significant unobservable inputs such as (a) volatility factors and (b) counterparty credit risk. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the strike prices fixed by our derivative contracts, and the resulting estimated future cash inflows or outflows over the contractual life are discounted to calculate the fair value. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differences and interest rates. Significant increases (decreases) in the quoted forward prices for commodities generally lead to corresponding decreases (increases) in the fair value measurement of our oil and gas derivative contracts. Significant changes in the volatility factors utilized in our option-pricing model can cause significant changes in the fair value measurement of our oil and gas derivative contracts. See Note 5, "Derivative Financial Instruments," for additional discussion of our derivative instruments.

The determination of the fair values of derivative instruments incorporates various factors that include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). Historically, we have not experienced significant changes in the fair value of our derivative contracts resulting from changes in counterparty credit risk as the counterparties for all of our derivative transactions have an “investment grade” credit rating.

Stock-Based Compensation. The calculation of the fair value of the SVAP liability requires the use of a probability-based Monte Carlo simulation, which includes unobservable inputs. The simulation predicts multiple scenarios of future stock returns over the performance period, which are discounted to calculate the fair value. The fair value is recognized over a service period derived from the simulation. Future stock returns and discounting variables are sensitive to market volatility. Significant increases (decreases) in the volatility factors utilized in our option-pricing model can cause significant increases (decreases) in the fair value measurement of the SVAP liability.

Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
 
 
Estimated Fair Value Asset (Liability)
 
Quantitative Information about Level 3 Fair Value Measurements
Instrument Type
 
Valuation
Technique
 
Unobservable Input
 
Range
 
 
(In millions)
 
 
 
 
 
 
 
 
Oil option and swaption contracts
 
$
(422
)
 
Black-Scholes
 
Oil price volatility
 
28.03
%
—
63.41%
 
 
 
 
 
 
Credit risk
 
0.01
%
—
1.76%
Natural gas option and swaption contracts
 
$
41

 
Black-Scholes
 
Natural gas price volatility
 
23.11
%
—
60.53%
 
 
 
 
 
 
Credit risk
 
0.01
%
—
1.12%
SVAP
 
$
(3
)
 
Monte Carlo
 
Implied volatility
 

 
50.2%
 









91

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



Fair Value of Debt

The estimated fair value of our notes, based on quoted prices in active markets (Level 1) as of December 31, was as follows: 
 
 
2014
 
2013
 
 
(In millions)
5¾% Senior Notes due 2022
 
$
772

 
$
767

5⅝% Senior Notes due 2024
 
989

 
1,025

7⅛% Senior Subordinated Notes due 2018
 
—

 
624

6⅞% Senior Subordinated Notes due 2020
 
721

 
755


Any amounts outstanding under our revolving credit facility and money market lines of credit are at variable rates as of the indicated dates and are stated at cost, which approximates fair value. Please see Note 9, "Debt."


9.
Debt:

At December 31, our debt consisted of the following: 
 
 
2014
 
2013
 
 
(In millions)
Senior unsecured debt:
 
 
 
 
Revolving credit facility — LIBOR based loans
 
$
345

 
$
585

Money market lines of credit(1)
 
101

 
64

Total credit arrangements
 
446

 
649

5¾% Senior Notes due 2022
 
750

 
750

5⅝% Senior Notes due 2024
 
1,000

 
1,000

Total senior unsecured debt
 
2,196

 
2,399

7⅛% Senior Subordinated Notes due 2018
 
—

 
600

6⅞% Senior Subordinated Notes due 2020
 
700

 
700

Discount on notes
 
(4
)
 
(5
)
Total long-term debt
 
$
2,892

 
$
3,694

 _________________
(1)
Because we have the ability and intent to use our available credit facility capacity to repay borrowings under our money market lines of credit as of the indicated dates, amounts outstanding under these obligations, if any, are classified as long-term.

Credit Arrangements

We have a revolving credit facility that matures in June 2018 and provides borrowing capacity of $1.4 billion. As of December 31, 2014, the largest individual loan commitment by any lender was 14% of total commitments.

Loans under the credit facility bear interest, at our option, equal to (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank, N.A. or the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 50 basis points, plus a margin that is based on a grid of our debt rating (75 basis points per annum at December 31, 2014) or (b) the London Interbank Offered Rate, plus a margin that is based on a grid of our debt rating (175 basis points per annum at December 31, 2014).


92

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Under our credit facility, we pay commitment fees on available but undrawn amounts based on a grid of our debt rating (30 basis points per annum at December 31, 2014). We incurred aggregate commitment fees under our credit facility of approximately $4 million, $3 million and $3 million for each of the years ended December 31, 2014, 2013 and 2012, respectively, which are recorded in “Interest expense” on our consolidated statement of operations.

Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and maintenance of a ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test writedowns and goodwill impairments) to interest expense of at least 3.0 to 1.0. At December 31, 2014, we were in compliance with all of our debt covenants.

As of December 31, 2014, we had no letters of credit outstanding under our credit facility. Letters of credit are subject to a fronting fee of 20 basis points and annual fees based on a grid of our debt rating (175 basis points at December 31, 2014).

Subject to compliance with the restrictive covenants in our credit facility, at December 31, 2014, we also had a total of $94 million of additional, available borrowing capacity under money market lines of credit with various financial institutions, the availability of which is at the discretion of the financial institutions.

The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; inaccuracy of representations and warranties in any material respect; a change of control; or certain other material adverse changes in our business. Our senior notes and senior subordinated notes also contain standard events of default. If any of the foregoing defaults were to occur, our lenders under the credit facility could terminate future lending commitments, and our lenders under both the credit facility and our notes could declare the outstanding borrowings due and payable. In addition, our credit facility, senior notes, senior subordinated notes and substantially all of our derivative arrangements contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations. See Note 1, " Organization and Principles of Consolidation – Concentration of Credit Risk," for additional details.

Senior Notes

In June 2012, we issued $1 billion of 5⅝% Senior Notes due 2024 and received proceeds of $990 million (net of offering costs). These notes were issued at par to yield 5⅝%. We used a portion of the net proceeds to repay borrowings outstanding under our credit facility and money market lines of credit as well as redeem our 6⅝% Senior Subordinated Notes due 2016.
Interest on our senior notes is payable semi-annually. The notes are unsecured and unsubordinated obligations and rank equally with all of our other existing and future unsecured and unsubordinated obligations. We may redeem some or all of our senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing our senior notes contain covenants that may limit our ability to, among other things, incur debt secured by liens; enter into sale/leaseback transactions; and enter into merger or consolidation transactions.
The indentures also provide that if any of our subsidiaries guarantee any of our indebtedness at any time in the future, then we will cause our senior notes to be equally and ratably guaranteed by that subsidiary. At December 31, 2014, we were in compliance with all of our debt covenants.
Senior Subordinated Notes
In October 2014, we redeemed our $600 million aggregate principal amount of 7⅛% Senior Subordinated Notes due 2018. In connection with the redemption, we paid a premium of $14 million. The premium was recorded under the caption "Other income (expense) — Other, net" on our consolidated statement of operations. In addition, unamortized offering costs of approximately $3 million were charged to interest expense as a result of the repayment.
We may redeem some or all of our 6⅞% Senior Subordinated Notes due 2020 at any time on or after February 1, 2015 at a redemption price stated in the indenture governing the notes. Interest on our senior subordinated notes is payable semi-annually. The notes are unsecured senior subordinated obligations that rank junior in right of payment to all of our present and future senior indebtedness.

93

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The indenture governing our senior subordinated notes may limit our ability under certain circumstances to, among other things:
•
incur additional debt;
•
make restricted payments; and
•
engage in mergers; consolidations; and sales and other dispositions of assets.

At December 31, 2014, we were in compliance with all of our debt covenants.
 

10.
Income Taxes:

For the years ended December 31, income (loss) from continuing operations before income taxes consisted of the following:

 
 
2014
 
2013
 
2012
 
 
(In millions)
U.S.
 
$
1,022

 
$
170

 
$
(1,414
)
International
 
10

 
31

 
40

Total income (loss) before income taxes
 
$
1,032

 
$
201

 
$
(1,374
)

For the years ended December 31, the total provision (benefit) for income taxes for continuing operations consisted of the following: 
 
 
2014
 
2013
 
2012
 
 
(In millions)
Current taxes:
 
 
 
 
 
 
U.S. federal
 
$
—

 
$
(4
)
 
$
1

U.S. state
 
2

 
—

 
1

International
 
3

 
2

 
14

Deferred taxes:
 
 
 
 
 
 
U.S. federal
 
350

 
53

 
(479
)
U.S. state
 
25

 
13

 
(34
)
International
 
2

 
64

 
45

Total provision (benefit) for income taxes
 
$
382

 
$
128

 
$
(452
)
The provision (benefit) for income taxes for continuing operations for the indicated years was different than the amount computed using the federal statutory rate (35%) for the following reasons: 
 
 
2014
 
2013
 
2012
 
 
(In millions)
Amount computed using the statutory rate
 
$
361

 
$
70

 
$
(481
)
Increase (decrease) in taxes resulting from:
 
 
 
 
 
 
State and local income taxes, net of federal effect
 
17

 
8

 
(18
)
Valuation allowance, state net of federal
 
—

 
(2
)
 
—

Foreign tax on foreign earnings
 
1

 
53

 
47

Other
 
3

 
(1
)
 
—

Total provision (benefit) for income taxes
 
$
382

 
$
128

 
$
(452
)


94

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In fourth quarter 2012, we made a decision to repatriate earnings from our international operations. By doing so we made an election to have our China business be treated as a disregarded entity for U.S. federal income tax purposes, which resulted in earnings and profits of our international business in China being taxed both in the United States and China. Due to our NOL carryforward position, we do not expect to be able to utilize related foreign tax credits (FTC) before they expire and accordingly recorded a full valuation allowance against these credits. These FTCs are utilized in the alternative minimum tax (AMT) system to reduce current cash taxes. The result is a high effective tax rate in periods where our book income in China is high relative to our domestic book income. These effective tax rate fluctuations are magnified when net income approaches zero.

At December 31, the components of our deferred tax asset (liability) were as follows: 
 
 
2014
 
2013
 
 
(In millions)
Deferred tax asset:
 
 
 
 
Net operating loss carryforwards
 
$
173

 
$
335

Alternative minimum tax credit
 
99

 
99

Stock-based compensation
 
26

 
25

Marketable securities
 
—

 
3

Oil and gas properties
 
—

 
59

Foreign tax credit
 
547

 
535

Commodity derivatives
 
—

 
13

Other
 
8

 
6

Total deferred tax asset
 
853

 
1,075

Deferred tax asset valuation allowances
 
(549
)
 
(584
)
Net deferred tax asset
 
304

 
491

 
 
 
 
 
Deferred tax liability:
 
 
 
 
Commodity derivatives
 
(217
)
 
—

Oil and gas properties
 
(1,715
)
 
(1,592
)
Total deferred tax liability
 
(1,932
)
 
(1,592
)
Net deferred tax liability
 
(1,628
)
 
(1,101
)
Less: Net current deferred tax asset (liability)
 
(144
)
 
22

Net noncurrent deferred tax liability
 
$
(1,484
)
 
$
(1,123
)
 
As of December 31, 2014 and 2013, we had gross net operating loss (NOL) carryforwards of approximately $0.5 billion and $1.0 billion for federal income tax and $1.6 billion and $1.7 billion for state income tax purposes, respectively, which may be used in future years to offset taxable income. NOL carryforwards of $155 million are subject to annual limitations due to stock ownership changes. We currently estimate that we will not be able to utilize $64 million of our various gross state NOLs because we do not have sufficient estimated future taxable income in the appropriate jurisdictions. To the extent not utilized, the federal NOL carryforwards will begin to expire during the years 2019 through 2033.

As of December 31, 2013, we had gross NOL carryforwards for international income tax purposes of approximately $17 million. In the fourth quarter of 2014, we wrote off the deferred tax asset and related valuation allowance since we have ceased operating in these jurisdictions and it is remote that the NOL carryforwards will be realized in the future.

As of December 31, 2014 and 2013, we had foreign tax credits of approximately $547 million and $535 million, respectively, which will expire during the years 2022 through 2024.

Utilization of deferred tax assets is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period. Estimates of future taxable income can be significantly affected by changes in oil, gas and NGL prices; estimates of the timing and amount of future production; and estimates of future operating and capital costs. Therefore, no certainty exists that we will be able to fully utilize our existing deferred tax assets.

95

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


The change in our deferred tax asset valuation allowance is as follows at December 31: 
 
 
2014
 
2013
 
2012
 
 
(In millions)
Balance at the beginning of the year
 
$
(584
)
 
$
(457
)
 
$
(11
)
Charged to provision for income taxes:
 
 
 
 
 
 
Malaysia valuation allowance
 
40

 
(15
)
 
(25
)
Foreign tax credit valuation allowance
 
(12
)
 
(114
)
 
(421
)
Brazil and other international valuation allowance
 
6

 
—

 
—

U.S. state net operating loss carryforwards
 
1

 
2

 
—

Balance at the end of the year
 
$
(549
)
 
$
(584
)
 
$
(457
)

As the result of the divestiture of the Malaysia operations in 2014, all of the deferred tax asset and related valuation allowance were transferred to the buyer. In the fourth quarter of 2014, we wrote off the other international deferred tax assets and related valuation allowances since we have ceased operating in these jurisdictions and it is remote that the NOL carryforwards will be realized in the future. In fourth quarter of 2014, 2013 and 2012, we recorded valuation allowances related to insufficient estimated future domestic taxable income to fully utilize foreign tax credits before they expire of $12 million, $114 million, and $421 million, respectively. The foreign tax credit deferred tax asset is fully offset by a valuation allowance. In 2014, we released $1 million of state valuation allowances due to utilization of the related state NOLs.


11.
Stock-Based Compensation:

For the years ended December 31, our stock-based compensation expense consisted of the following: 
 
 
2014
 
2013
 
2012
 
 
(In millions)
Equity awards
 
$
47

 
$
48

 
$
46

Liability awards:
 


 


 


Stockholder Value Appreciation Program
 
38

 
18

 
—

Cash-settled restricted stock units
 
20

 
9

 
1

Total liability awards
 
58

 
27

 
1

Total stock-based compensation
 
105

 
75

 
47

Capitalized in oil and gas properties
 
(40
)
 
(20
)
 
(12
)
Net stock-based compensation expense
 
$
65

 
$
55

 
$
35


As of December 31, 2014, we had approximately $70 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards. The full amount is expected to be recognized within four years.

Equity Awards

Equity awards consist of service-based and performance- or market-based restricted stock units, stock options and stock purchase options under the Employee Stock Purchase Plan.

Stock-based compensation classified as equity awards to employees and non-employee directors are currently granted under the 2011 Omnibus Stock Plan (2011 Plan). The fair value of grants is determined utilizing the Black-Scholes option-pricing model for stock options and a Monte Carlo lattice-based model for our performance- and market-based restricted stock and restricted stock units. Compensation expense for equity awards is expected to be recognized on a straight-line basis over the applicable remaining vesting periods.


96

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Shares available for grant under our 2011 Plan are reduced by 1.87 times the number of shares of restricted stock or restricted stock units awarded under the plan and are reduced by 1 times the number of shares subject to stock options awarded under the plan. At December 31, 2014, we had approximately (1) 2.3 million additional shares available for issuance pursuant to our existing plan if all future awards under our 2011 Plan are stock options, or (2) 1.2 million additional shares available for issuance pursuant to our existing plan if all future awards under our 2011 Plan are restricted stock or restricted stock units. Thus far, the majority of the awards under our 2011 Plan have been granted as restricted stock unit awards.

Restricted Stock.    At December 31, 2014, our employees held approximately 1.9 million shares of non-vested restricted stock and restricted stock units. These shares primarily vest over three to five years and vesting is dependent upon the employee’s continued service with our Company. In addition, at December 31, 2014, our employees held approximately 0.9 million shares of restricted stock subject to performance-based vesting criteria (all of which are currently considered market-based restricted stock under authoritative accounting guidance). To the extent we have treasury shares available, we utilize treasury shares when restricted stock is issued or restricted stock units vest.

The following table provides information about restricted stock and restricted stock unit activity. 
 
 
Service-Based
Shares
 
Performance/
Market-Based
Shares
 
Total
Shares
 
Weighted-
Average
Grant Date
Fair Value
per Share
 
 
(In thousands, except per share data)
Non-vested shares outstanding at January 1, 2012
 
2,123

 
357

 
2,480

 
$
49.52

Granted
 
1,589

 
184

 
1,773

 
35.29

Forfeited
 
(364
)
 
(14
)
 
(378
)
 
47.34

Vested
 
(977
)
 
(89
)
 
(1,066
)
 
41.70

Non-vested shares outstanding at December 31, 2012
 
2,371

 
438

 
2,809

 
43.31

Granted
 
2,428

 
300

 
2,728

 
27.24

Forfeited
 
(605
)
 
(32
)
 
(637
)
 
39.47

Vested
 
(1,195
)
 
—

 
(1,195
)
 
39.64

Non-vested shares outstanding at December 31, 2013
 
2,999

 
706

 
3,705

 
33.31

Granted
 
465

 
338

 
803

 
25.42

Forfeited
 
(416
)
 
(69
)
 
(485
)
 
25.14

Vested
 
(1,146
)
 
(30
)
 
(1,176
)
 
36.64

Non-vested shares outstanding at December 31, 2014
 
1,902

 
945

 
2,847

 
$
30.05


The total fair value of restricted stock and restricted stock units that vested during the years ended December 31, 2014, 2013 and 2012 was $43 million, $47 million and $44 million, respectively.

Stock Options.    Options generally expire ten years from the date of grant and become exercisable at the rate of 20% per year. The exercise price of options cannot be less than the fair market value per share of our common stock on the date of grant. We issue new shares of stock when stock options are exercised.

The excess tax benefit realized from stock options exercised is recognized as a credit to additional paid-in capital and is calculated as the amount by which the tax deduction we receive exceeds the deferred tax asset associated with recorded stock-based compensation expense. We did not realize an excess tax benefit from stock-based compensation for 2014, 2013 or 2012 because we did not have sufficient taxable income to fully realize the deduction. At December 31, 2014, we had unrecognized net operating losses of $99 million related to stock-based compensation.

The following table below provides information about stock option activity. 

97

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 
Number of
Shares
Underlying
Options
 
Weighted-
Average
Exercise
Price
per Share
 
Weighted-
Average
Grant Date
Fair Value
per Share
 
Weighted-
Average Remaining
Contractual Life
 
Aggregate
Intrinsic
Value(1)
 
 
(In thousands)
 
 
 
 
 
(In years)
 
(In millions)
Outstanding at January 1, 2012
 
1,059

 
$
36.31

 
 
 
4.0
 
$
7

Granted
 
—

 
—

 
$
—

 
 
 
 
Exercised
 
(94
)
 
19.52

 
 
 
 
 
1

Forfeited
 
(64
)
 
36.19

 
 
 
 
 
 
Outstanding at December 31, 2012
 
901

 
38.06

 
 
 
3.3
 
1

Granted
 
—

 
—

 
—

 
 
 
 
Exercised
 
(53
)
 
19.68

 
 
 
 
 
1

Forfeited
 
(161
)
 
37.26

 
 
 
 
 
 
Outstanding at December 31, 2013
 
687

 
39.68

 
 
 
1.9
 
—

Granted
 
—

 
—

 
—

 
 
 
 
Exercised
 
(134
)
 
29.32

 
 
 
 
 
1

Forfeited
 
(252
)
 
40.10

 
 
 
 
 
 
Outstanding at December 31, 2014
 
301

 
$
43.93

 
 
 
2.2
 
$
—

Exercisable at December 31, 2014
 
301

 
$
43.93

 
 
 
2.2
 
$
—

 _________________
(1)
The intrinsic value of a stock option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option.

On December 31, 2014, the last reported sales price of our common stock on the New York Stock Exchange was $27.12 per share.

The following table summarizes information about stock options outstanding and exercisable at December 31, 2014: 
Options Outstanding
 
Options Exercisable
Range of Exercise Prices
 
Number of
Shares
Underlying
Options
 
Weighted-
Average
Remaining
Contractual Life
 
Weighted-
Average
Exercise Price
per Share
 
Number of
Shares
Underlying
Options
 
Weighted-
Average
Exercise Price
per Share
 
 
(In thousands)
 
(In years)
 
 
 
(In thousands)
 
 
$27.51 to $35.00
 
66

 
0.1
 
$
31.94

 
66

 
$
31.94

  35.01 to 41.72
 
27

 
0.3
 
38.44

 
27

 
38.44

  41.73 to 48.45
 
208

 
3.1
 
48.45

 
208

 
48.45

 
 
301

 
2.2
 
$
43.93

 
301

 
$
43.93

    
Employee Stock Purchase Plan.    In May 2010, our stockholders approved the Newfield Exploration Company 2010 Employee Stock Purchase Plan with one million shares of our common stock available for issuance. Pursuant to our employee stock purchase plan, for each six-month period beginning on January 1 or July 1 during the term of the plan, each eligible employee has the opportunity to purchase our common stock for a purchase price equal to 85% of the lesser of the fair market value of our common stock on the first or last day of the period. Each employee may purchase up to $25,000 in common stock per calendar year. Employees of our foreign subsidiaries are not eligible to participate in the plan.

During 2014, options to purchase 168,394 shares of our common stock were issued under our employee stock purchase plan. The weighted-average fair value of each option was $7.91 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free weighted-average interest rate of 0.07%, an expected life of six months and weighted-average volatility of 32.05%. At December 31, 2014, approximately 356,000 shares of our common stock remained available for issuance under the current plan.

98

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


During 2013, options to purchase 178,733 shares of our common stock were issued under our employee stock purchase plan. The weighted-average fair value of each option was $6.59 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free weighted-average interest rate of 0.10%, an expected life of six months and weighted-average volatility of 39.45%.

During 2012, options to purchase 165,722 shares of our common stock were issued under our employee stock purchase plan. The weighted-average fair value of each option was $9.86 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free weighted-average interest rate of 0.10%, an expected life of six months and weighted-average volatility of 49.43%.

Liability Awards

Liability awards consist of performance awards that are settled in cash instead of shares as discussed below.

Stockholder Value Appreciation Program. In September 2013, the Compensation and Management Development Committee of the Board approved the SVAP to be administered under the 2011 Plan. The SVAP pays substantially all full-time domestic, nonexecutive employees a cash payment based on a percentage of salary upon each incremental $5 increase in our 30 -calendar day average share price. Each price threshold can be reached only once during the term of the program. The SVAP's performance period lasts through December 31, 2015. Each price trigger that is reached results in an approximately $13 million payment.

The first price threshold that triggered a payment under the SVAP was $27.50 during the fourth quarter of 2013. The second and third price thresholds for the SVAP were $32.50 and $37.50, respectively, which were reached during the second quarter of 2014. The fourth price threshold for the SVAP of $42.50 was reached in July 2014.

Based on the valuation of the SVAP as of December 31, 2014, the fair value was $4 million, of which $3 million has been accrued. The total expected cost was determined using a Monte Carlo simulation assuming no dividends, a risk-free weighted-average interest rate of 0.27%, a plan term of one year and an average of implied and historical stock price volatility of 47%. An additional $1 million is expected to be recognized over the remaining service period of the plan. Future changes in our stock price could cause the total cost of the plan to be significantly different than our estimates as of December 31, 2014.

Cash-Settled Restricted Stock Units.    We also have granted cash-settled restricted stock units to employees that vest over three years. As of December 31, 2014, we accrued $12 million for future cash settlement upon vesting of awards. The value of the awards, and the associated stock-based compensation expense, is based on the Company's stock price at the end of each period. During the year ended December 31, 2014, we granted approximately 759,000 cash-settled restricted stock units to employees. During the year ended December 31, 2014, approximately 587,000 cash-settled restricted stock units vested and settled for approximately $19 million. During the year ended December 31, 2013, approximately 85,000 cash-settled restricted units vested and settled for approximately $2 million. As of December 31, 2014, we had approximately 1.2 million cash-settled restricted stock units outstanding and related unrecognized stock-based compensation expense of approximately $18 million.
 

12.
Employee Benefit Plans:

Post-Retirement Medical Plan

We sponsor a post-retirement medical plan that covers all retired employees until they reach age 65. At December 31, 2014, both our accumulated benefit obligation and our accrued benefit costs were $16 million. Our net periodic benefit cost was approximately $2 million for each of the years ended December 31, 2014, 2013 and 2012.

The expected future benefit payments under our post-retirement medical plan for the next ten years include $5 million for the five-year period 2015 through 2019 and $7 million for the five-year period 2020 through 2024.
 
    


99

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Annual Cash Incentive Compensation Plan

During 2010, our Board of Directors, with the recommendation of the Compensation & Management Development Committee, approved a new annual cash incentive compensation plan for all employees (the 2011 Annual Incentive Plan). Under the 2011 Annual Incentive Plan, the Compensation & Management Development Committee determines the annual award pool for all employees based upon a number of factors including the Company’s performance against stated performance goals and in comparison with peer companies in our industry. All employees are eligible if employed on October 1 and December 31 of the performance period. Beginning with the year ended December 31, 2010, our annual cash incentive compensation is paid in a single payment to employees during the first quarter after the end of the performance period.

Total incentive compensation expense under the 2011 Annual Incentive Plan for the years ended December 31, 2014, 2013 and 2012 was $45 million, $40 million and $41 million, respectively.

401(k) and Deferred Compensation Plans

We sponsor a 401(k) profit sharing plan under Section 401(k) of the Internal Revenue Code. This plan covers all of our employees, excluding those of our foreign subsidiaries. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the IRS. We also sponsor a highly compensated employee deferred compensation plan. This non-qualified plan allows an eligible employee to defer a portion of his or her salary or bonus on an annual basis. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the plan. Our contribution with respect to each participant in the deferred compensation plan is reduced by the amount of contribution made by us to our 401(k) plan for that participant. Our combined contributions to these two plans was $10 million for each of the years ended December 31, 2014, 2013 and 2012.


13.
Commitments and Contingencies:

We have various commitments from continuing operations for firm transportation, operating lease agreements for office space and other agreements. As of December 31, 2014, future minimum payments under these non-cancelable agreements are as follows:
 
 
Firm
Transportation
 
Operating
Leases
(Office Space)
 
Drilling-Related
 
Other
 
Total
 
 
(In millions)
Year Ending December 31,
 
 
 
 
 
 
 
 
 
 
2015
 
$
72

 
$
18

 
$
196

 
$
26

 
$
312

2016
 
85

 
15

 
36

 
16

 
152

2017
 
82

 
15

 
—

 
13

 
110

2018
 
63

 
14

 
—

 
12

 
89

2019
 
52

 
12

 
—

 
11

 
75

Thereafter
 
35

 
24

 
—

 
35

 
94

Total minimum future payments
 
$
389

 
$
98

 
$
232

 
$
113

 
$
832


Firm transportation is comprised of various agreements with third parties for oil and gas gathering and transportation. Rent expense with respect to our lease commitments for office space for the years ended December 31, 2014, 2013 and 2012 was $20 million, $19 million and $17 million, respectively. Our other agreements are primarily other equipment leases. Payments under our drilling-related contracts are accounted for as capital additions to our oil and gas properties.





100

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)




We have various oil and gas production volume delivery commitments that are related to our domestic operations. As of December 31, 2014, our delivery commitments through 2025 were as follows: 
 
 
Natural
Gas
 
Oil(1)
Year Ending December 31,
 
(MMMBtus)
 
(MBbls)
2015
 
15,372

 
6,570

2016
 
—

 
13,908

2017
 
—

 
13,870

2018
 
—

 
13,870

2019
 
—

 
13,870

Thereafter
 
—

 
46,576

Total delivery commitments
 
15,372

 
108,664

 _________________
(1)
Our oil delivery commitments include commitments with Salt Lake City, Utah refiners. Our delivery commitments are for approximately 18,000 barrels of oil per day through 2020 and an additional 20,000 barrels of oil per day expected to start in 2016 and continuing through 2025. The 20,000 barrel per day delivery commitment represents approximately 7,300 MBbls of our committed oil volumes for each of the years 2016 through 2025. The timing may change due to timing of the refinery expansion completion. These commitments relate to our Uinta Basin production.

Given the recent decline in oil and natural gas prices and the related impact on our 2015 planned capital investments as well as the potential impact on development plans in future years, we could fail to deliver the minimum production required under these commitments. In the event that we are unable to meet our crude oil volume delivery commitments, we would incur deficiency fees ranging from $1.83 to $6.50 per barrel.

Litigation

We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

During the fourth quarter 2012, we settled a lawsuit where the Company was the plaintiff and recorded a gain of $13 million in “Other income (expense) — Other, net” on our consolidated statement of operations.
 


101

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


14.
Segment Information

While we only have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments. Our current operating segments are the United States and China. Prior to classifying our Malaysia business as held for sale and discontinued operations, we reported a business segment for Malaysia. The accounting policies of each of our operating segments are the same as those described in Note 1, “Organization and Summary of Significant Accounting Policies.”

The following tables provide the geographic operating segment information for our continuing operations for the years ended December 31, 2014, 2013 and 2012. Income tax allocations have been determined based on statutory rates in the applicable geographic segment. In order to reflect the double taxation of our earnings and profits in China, we have applied the statutory rates for China and the U.S. to determine our income tax allocation for our China operations in the following three tables.



Domestic

China

Total
 

(In millions)
Year Ended December 31, 2014:






Oil, gas and NGL revenues

$
2,249


$
39


$
2,288

Operating expenses:






Lease operating

309


12


321

Transportation and processing

174


—


174

Production and other taxes

105


6


111

Depreciation, depletion and amortization

857


13


870

General and administrative

221


1


222

Other

15


—


15

Allocated income tax (benefit)

210

 
5

 
 
Net income (loss) from oil and gas properties

$
358


$
2



Total operating expenses





1,713

Income (loss) from continuing operations





575

Interest expense, net of interest income, capitalized interest and other





(153
)
Commodity derivative income (expense)





610

Income (loss) from continuing operations before income taxes





$
1,032

Total assets

$
8,870


$
728


$
9,598

Additions to long-lived assets

$
2,044


$
156


$
2,200



102

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



Domestic

China

Total
 

(In millions)
Year Ended December 31, 2013:






Oil, gas and NGL revenues

$
1,788


$
69


$
1,857

Operating expenses:






Lease operating

276


8


284

Transportation and processing

137


—


137

Production and other taxes

67


12


79

Depreciation, depletion and amortization

668


17


685

General and administrative

219


—


219

Other

3


—


3

Allocated income tax (benefit)

155


19



Net income (loss) from oil and gas properties

$
263


$
13



Total operating expenses





1,407

Income (loss) from continuing operations





450

Interest expense, net of interest income, capitalized interest and other





(152
)
Commodity derivative income (expense)





(97
)
Income (loss) from continuing operations before income taxes





$
201

Total assets(1)

$
7,863


$
542


$
8,405

Additions to long-lived assets

$
1,932


$
174


$
2,106

 _________________
(1)
Excludes total assets from our discontinued operations of $916 million.


103

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



Domestic

China

Total
 

(In millions)
Year Ended December 31, 2012:






Oil, gas and NGL revenues

$
1,476


$
86


$
1,562

Operating expenses:






Lease operating

299


7


306

Transportation and processing

107


—


107

Production and other taxes

67


18


85

Depreciation, depletion and amortization

683


21


704

General and administrative

211


—


211

Ceiling test impairment

1,488


—


1,488

Other

15


—


15

Allocated income tax (benefit)

(516
)

24



Net income (loss) from oil and gas properties

$
(878
)

$
16



Total operating expenses





2,916

Income (loss) from continuing operations





(1,354
)
Interest expense, net of interest income, capitalized interest and other





(140
)
Commodity derivative income (expense)





120

Income (loss) from continuing operations before income taxes





$
(1,374
)
Total assets(1)

$
6,699


$
347


$
7,046

Additions to long-lived assets

$
1,655


$
87


$
1,742

 _________________
(1)
Excludes total assets from our discontinued operations of $866 million.


15.
Supplemental Cash Flows Information:

The following table presents information about supplemental cash flows for each of the years in the three-year period ended December 31: 
 
 
2014
 
2013
 
2012
 
 
(In millions)
Cash Payments:
 
 
 
 
 
 
  Interest payments
 
$
144

 
$
148

 
$
137

Income tax payments
 
4

 
128

 
206

Non-cash investing and financing activities excluded from the statement of cash flows:
 
 
 
 
 
 
(Increase) decrease in receivables for property sales
 
$
(17
)
 
$
12

 
$
25

(Increase) decrease in accrued capital expenditures
 
(1
)
 
(75
)
 
(124
)
(Increase) decrease in asset retirement costs
 
(56
)
 
(125
)
 
(8
)


16.
Related Party Transaction:

Kevin M. Robinson, our former Vice President — Asia through February 10, 2014, and Susan G. Riggs, our current Treasurer, were minority owners of Huffco International L.L.C. (Huffco). In May 1997, before Mr. Robinson and Ms. Riggs

104

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

joined the Company, we acquired from Huffco an entity now known as Newfield China, LDC, the owner of a 12% interest in a three-field unit located in Bohai Bay, offshore China. Huffco retained preferred shares of Newfield China that provided for dividend payments. During the third quarter of 2013, we purchased the outstanding preferred shares of Newfield China from Huffco for approximately $20 million, which was recorded as a charge against retained earnings.


17. Subsequent Events:
    
As a result of decreasing commodity pricing and projected lower capital spending for 2015, the Company executed a reduction in force during the first quarter of 2015, which reduced approximately 15% of the total headcount. We incurred severance and related costs as a result of these workforce reductions totaling approximately $10 million, which will be reflected in our first quarter 2015 financial statements.


18.
Quarterly Results of Operations (Unaudited):

The results of operations by quarter for the indicated periods are as follows: 
 
 
2014 Quarter Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(In millions, except per share data)
Oil, gas and NGL revenues(1)
 
$
571

 
$
612

 
$
610

 
$
495

Income (loss) from operations(1)
 
182

 
180

 
167

 
46

 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations, net of tax
 
$
27

 
$
(23
)
 
$
279

 
$
367

Income (loss) from discontinued operations, net of tax(2)
 
257

 
1

 
(1
)
 
(7
)
Net income (loss)
 
$
284

 
$
(22
)
 
$
278

 
$
360

Basic earnings (loss) per common share(3)
 


 


 


 


Income (loss) from continuing operations
 
$
0.19

 
$
(0.16
)
 
$
2.04

 
$
2.67

Income (loss) from discontinued operations
 
1.89

 
—

 
—

 
(0.05
)
Basic earnings (loss) per share
 
$
2.08

 
$
(0.16
)
 
$
2.04

 
$
2.62

Diluted earnings (loss) per common share(3)
 


 


 


 


Income (loss) from continuing operations
 
$
0.19

 
$
(0.16
)
 
$
2.01

 
$
2.65

Income (loss) from discontinued operations
 
1.88

 
—

 
—

 
(0.05
)
Diluted earnings (loss) per share
 
$
2.07

 
$
(0.16
)
 
$
2.01

 
$
2.60

 

105

NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 
2013 Quarter Ended
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(In millions, except per share data)
Oil, gas and NGL revenues(1)
 
$
393

 
$
449

 
$
505

 
$
510

Income (loss) from operations(1)
 
91

 
93

 
140

 
126

 
 


 


 


 


Income (loss) from continuing operations, net of tax
 
$
(21
)
 
$
107

 
$
3

 
$
(16
)
Income (loss) from discontinued operations, net of tax
 
13

 
4

 
24

 
33

Net income (loss)
 
$
(8
)
 
$
111

 
$
27

 
$
17

Basic earnings (loss) per common share(3)
 


 


 


 


Income (loss) from continuing operations(4)
 
$
(0.15
)
 
$
0.79

 
$
(0.13
)
 
$
(0.12
)
Income (loss) from discontinued operations
 
0.09

 
0.03

 
0.18

 
0.25

Basic earnings (loss) per share
 
$
(0.06
)
 
$
0.82

 
$
0.05

 
$
0.13

Diluted earnings (loss) per common share(3)
 


 


 


 


Income (loss) from continuing operations(4)
 
$
(0.15
)
 
$
0.79

 
$
(0.13
)
 
$
(0.12
)
Income (loss) from discontinued operations
 
0.09

 
0.03

 
0.18

 
0.25

Diluted earnings (loss) per share
 
$
(0.06
)
 
$
0.82

 
$
0.05

 
$
0.13

 _________________
(1)
Oil, gas and NGL revenues and Income (loss) from operations are specific to our continuing operations.
(2)
During the quarter ended March 31, 2014, we sold our Malaysia business and recorded a gain of approximately $388 million ($252 million, after tax). During the fourth quarter, we reduced the previously recognized gain by $15 million ($10 million, after tax) due to recording an allowance against a receivable. See Note 3, "Discontinued Operations," for additional information.
(3)
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.
(4)
Basic and diluted earnings per share includes an adjustment of $20 million related to the repurchase of preferred shares of a now wholly-owned subsidiary. See Note 2, "Earnings Per Share" for additional detail.

106

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED

Results of Operations for Oil and Gas Producing Activities


The following tables present the results of our oil and gas producing activities for the years ending December 31: 
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China
 
Malaysia
 
Total
 
 
(In millions)
2014:
 
 
 
 
 
 
 
 
Revenues
 
$
2,240

 
$
39

 
$
90

 
$
2,369

Production costs
 
299

 
12

 
11

 
322

Production taxes and other operating expenses
 
279

 
6

 
25

 
310

Depreciation, depletion and amortization
 
857

 
13

 
33

 
903

Income taxes
 
282

 
2

 
8

 
292

Results of operations for oil and gas producing activities
 
$
523

 
$
6

 
$
13

 
$
542

 
 
 
 
 
 
 
 
 
2013:
 
 
 
 
 
 
 
 
Revenues
 
$
1,777

 
$
69

 
$
822

 
$
2,668

Production costs
 
265

 
8

 
117

 
390

Production taxes and other operating expenses
 
204

 
12

 
272

 
488

Depreciation, depletion and amortization
 
668

 
18

 
244

 
930

Income taxes
 
224

 
8

 
72

 
304

Results of operations for oil and gas producing activities
 
$
416

 
$
23

 
$
117

 
$
556

 
 
 
 
 
 
 
 
 
2012:
 
 
 
 
 
 
 
 
Revenues
 
$
1,469

 
$
86

 
$
1,005

 
$
2,560

Production costs
 
292

 
7

 
101

 
400

Production taxes and other operating expenses
 
174

 
18

 
259

 
451

Depreciation, depletion and amortization
 
683

 
21

 
251

 
955

Impairment of oil and gas properties
 
1,488

 
—

 
—

 
1,488

Income taxes
 
(410
)
 
10

 
150

 
(250
)
Results of operations for oil and gas producing activities
 
$
(758
)
 
$
30

 
$
244

 
$
(484
)













107

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Costs Incurred

The following tables present costs incurred for oil and gas property acquisitions, exploration and development for the respective years: 
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China
 
Malaysia
 
Total
 
 
(In millions)
2014:
 
 
 
 
 
 
 
 
Property acquisitions:
 
 
 
 
 
 
 
 
Unproved
 
$
146

 
$
—

 
$
—

 
$
146

Proved
 
6

 
—

 
—

 
6

Exploration
 
1,089

 
—

 
—

 
1,089

Development(1)
 
772

 
156

 
14

 
942

Total costs incurred(2)
 
$
2,013

 
$
156

 
$
14

 
$
2,183

 
 
 
 
 
 
 
 
 
2013:
 
 
 
 
 
 
 
 
Property acquisitions:
 
 
 
 
 
 
 
 
Unproved
 
$
154

 
$
—

 
$
—

 
$
154

Proved
 
8

 
1

 
—

 
9

Exploration
 
966

 
33

 
101

 
1,100

Development(1)
 
691

 
140

 
211

 
1,042

Total costs incurred(2)
 
$
1,819

 
$
174

 
$
312

 
$
2,305

 
 
 
 
 
 
 
 
 
2012:
 
 
 
 
 
 
 
 
Property acquisitions:
 
 
 
 
 
 
 
 
Unproved
 
$
64

 
$
—

 
$
—

 
$
64

Proved
 
3

 
—

 
—

 
3

Exploration
 
929

 
1

 
63

 
993

Development(1)
 
659

 
86

 
108

 
853

Total costs incurred(2)
 
$
1,655

 
$
87

 
$
171

 
$
1,913

 _________________
(1)
Includes $56 million, $121 million and $9 million for 2014, 2013 and 2012, respectively, of asset retirement costs.

(2)
Other items impacting the capitalized costs of our oil and gas properties which are not included in total costs incurred are as follows:
 
 
2014
 
2013
 
2012
 
 
(In millions)
Property sales — Domestic
 
$
635

 
$
23

 
$
606

Property sales — International
 
1,571

 
—

 
—

Ceiling test writedown — Domestic
 
—

 
—

 
1,488

 
 
$
2,206

 
$
23

 
$
2,094




108

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Capitalized Costs

Capitalized costs for our oil and gas producing activities consisted of the following at the end of each of the years in the two-year period ended December 31, 2014: 
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China
 
Malaysia
 
Total
 
 
(In millions)
December 31, 2014:
 
 
 
 
 
 
 
 
Proved properties
 
$
14,998

 
$
709

 
$
—

 
$
15,707

Unproved properties
 
677

 
—

 
—

 
677

 
 
15,675

 
709

 
—

 
16,384

Accumulated depreciation, depletion and amortization
 
(8,022
)
 
(130
)
 
—

 
(8,152
)
Net capitalized costs
 
$
7,653

 
$
579

 
$
—

 
$
8,232

 
 
 
 
 
 
 
 
 
December 31, 2013:
 
 
 
 
 
 
 
 
Proved properties
 
$
13,185

 
$
550

 
$
1,441

 
$
15,176

Unproved properties
 
1,116

 
—

 
115

 
1,231

 
 
14,301

 
550

 
1,556

 
16,407

Accumulated depreciation, depletion and amortization
 
(7,185
)
 
(112
)
 
(1,009
)
 
(8,306
)
Net capitalized costs
 
$
7,116

 
$
438

 
$
547

 
$
8,101


Reserves

Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

Reserves Estimates.    All reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. The preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data input into our reserves forecasting and economics evaluation software, as well as multi-discipline management reviews. The technical employee responsible for overseeing the preparation of the reserves estimates has a Bachelor of Science in Petroleum Engineering, with more than 30 years of experience (including over 20 years of experience in reserve estimation).

Our reserves estimates are made using available geological and reservoir data as well as production performance data. These estimates, made by our petroleum engineering staff, are reviewed annually with management and revised, either upward or downward, as warranted by additional data. The data reviewed includes, among other things, seismic data, well logs, production tests, reservoir pressures, and individual well and field performance data. The data incorporated into our interpretations includes structure and isopach maps, individual well and field performance and other engineering and geological work products such as material balance calculations and reservoir simulation to arrive at conclusions about individual well and field projections. Additionally, offset performance data, operating expenses, capital costs and product prices factor into estimating quantities of reserves. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental regulations, as well as changes in the expected recovery rates associated with development drilling. Sustained decreases in prices, for example, may cause a reduction in some reserves due to reaching economic limits sooner.

Reserves Activity Overview.    The following is a discussion of our proved reserves and reserve additions and revisions. 

109

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(MMBOE)
Proved Reserves:
 
 
 
 
 
 
Beginning of year
 
612

 
566

 
652

Reserve additions
 
81

 
82

 
86

Reserve revisions
 
51

 
14

 
(91
)
Sales
 
(49
)
 
(1
)
 
(30
)
Production
 
(50
)
 
(49
)
 
(51
)
End of year
 
645

 
612

 
566


Our proved crude oil and condensate reserves at year-end 2014 were 301 million barrels compared to 270 million barrels and 237 million barrels at year-end 2013 and 2012, respectively. Our proved NGL reserves at year-end 2014 were 76 million barrels compared to 68 million barrels and 37 million barrels at year-end 2013 and 2012, respectively. Our proved natural gas reserves at year-end 2014 were 1.6 Tcf compared to 1.6 Tcf and 1.8 Tcf year-end 2013 and 2012, respectively. Liquids comprised about 58%, 55% and 48% of our proved reserves at year-end 2014, 2013 and 2012, respectively.

Reserve Additions and Revisions.    During 2014, our proved reserves increased 132 MMBOE as a result of additions (extensions, discoveries, improved recovery and purchases of reserves in place) and revisions of previous estimates. We expect the majority of future reserve growth to be associated with infill drilling, extensions of current fields and new discoveries, as well as improved recovery operations and purchases of proved properties. The success of these operations will directly impact reserve additions or revisions in the future.

Additions.    We added 72 MMBOE of proved reserves through discoveries, extensions and other additions, and 9 MMBOE through purchases. Drilling additions related to our domestic resource plays constituted 99% of our additions. Of the drilling additions, 52 MMBOE were proved undeveloped additions and 54 million barrels were liquids reserves.

Revisions.    Total proved reserve revisions in 2014 were a positive 51 MMBOE or 8% of the beginning of year proved reserves. They included a positive 3 MMBOE price revision which was primarily related to our onshore natural gas plays. In mature plays, dominated by infill drilling and where reserve growth cannot be classified as an extension or discovery, the change in reserves is captured as a revision. In 2014, our revisions associated with the development of existing fields were a positive 77 MMBOE. The remaining 29 MMBOE negative revisions are associated with development plan changes and well performance.

Sales.    In 2014, 2013 and 2012, we sold proved reserves associated with non-strategic assets and acreage trades.







110

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Estimated Net Quantities of Proved Oil and Gas Reserves

The following table sets forth our total net proved reserves and our total net proved developed and undeveloped reserves as of December 31, 2011, 2012, 2013 and 2014 and the changes in our total net proved reserves during the three-year period ended December 31, 2014: 
 
 
Crude Oil
and Condensate (MMBbls)
 
Natural Gas (Bcf)
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China(1)
 
Malaysia(1)
 
Total
 
Domestic
 
China(1)
 
Malaysia(1)
 
Total
Proved developed and undeveloped reserves as of:
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
204

 
20

 
23

 
247

 
2,329

 
—

 
4

 
2,333

Revisions of previous estimates
 
(13
)
 
—

 
2

 
(11
)
 
(525
)
 
—

 
(2
)
 
(527
)
Extensions, discoveries and other additions
 
38

 
—

 
—

 
38

 
181

 
—

 
—

 
181

Purchases of properties
 
—

 
—

 
—

 
—

 
1

 
—

 
—

 
1

Sales of properties
 
(15
)
 
—

 
—

 
(15
)
 
(80
)
 
—

 
—

 
(80
)
Production
 
(11
)
 
(1
)
 
(10
)
 
(22
)
 
(151
)
 
—

 
(2
)
 
(153
)
December 31, 2012
 
203

 
19

 
15

 
237

 
1,755

 
—

 
—

 
1,755

Revisions of previous estimates
 
19

 
7

 
2

 
28

 
(166
)
 
—

 
—

 
(166
)
Extensions, discoveries and other additions
 
25

 
—

 
2

 
27

 
187

 
—

 
—

 
187

Purchases of properties
 
1

 
—

 
—

 
1

 
1

 
—

 
—

 
1

Sales of properties
 
—

 
—

 
—

 
—

 
(5
)
 
—

 
—

 
(5
)
Production
 
(14
)
 
(1
)
 
(8
)
 
(23
)
 
(124
)
 
—

 
—

 
(124
)
December 31, 2013
 
234

 
25

 
11

 
270

 
1,648

 
—

 
—

 
1,648

Revisions of previous estimates
 
18

 
(2
)
 
—

 
16

 
129

 
—

 
—

 
129

Extensions, discoveries and other additions
 
41

 
1

 
—

 
42

 
112

 
—

 
—

 
112

Purchases of properties
 
6

 
—

 
—

 
6

 
9

 
—

 
—

 
9

Sales of properties
 
(3
)
 
—

 
(10
)
 
(13
)
 
(164
)
 
—

 
—

 
(164
)
Production
 
(18
)
 
(1
)
 
(1
)
 
(20
)
 
(127
)
 
—

 
—

 
(127
)
December 31, 2014
 
278

 
23

 
—

 
301

 
1,607

 
—

 
—

 
1,607

Proved developed reserves as of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
88

 
5

 
17

 
110

 
1,405

 
—

 
4

 
1,409

December 31, 2012
 
92

 
4

 
14

 
110

 
1,042

 
—

 
—

 
1,042

December 31, 2013
 
112

 
4

 
11

 
127

 
1,055

 
—

 
—

 
1,055

December 31, 2014
 
135

 
9

 
—

 
144

 
938

 
—

 
—

 
938

Proved undeveloped reserves as of:
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
116

 
15

 
6

 
137

 
924

 
—

 
—

 
924

December 31, 2012
 
111

 
15

 
1

 
127

 
713

 
—

 
—

 
713

December 31, 2013
 
122

 
21

 
—

 
143

 
593

 
—

 
—

 
593

December 31, 2014
 
143

 
14

 
—

 
157

 
669

 
—

 
—

 
669

 _________________
(1)
All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method. We used the economic interest method in Malaysia until we sold our Malaysia business in 2014.
 

111

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)






Estimated Net Quantities of Proved Oil and Gas Reserves — (Continued)
 
 
NGLs (MMBbls)
 
Total Oil Equivalents (MMBOE)
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China(1)
 
Malaysia(1)
 
Total
 
Domestic
 
China(1)
 
Malaysia(1)
 
Total
Proved developed and undeveloped reserves as of:
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
16

 
—

 
—

 
16

 
608

 
20

 
24

 
652

Revisions of previous estimates
 
9

 
—

 
—

 
9

 
(92
)
 
—

 
1

 
(91
)
Extensions, discoveries and other additions
 
17

 
—

 
—

 
17

 
86

 
—

 
—

 
86

Purchases of properties
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Sales of properties
 
(2
)
 
—

 
—

 
(2
)
 
(30
)
 
—

 
—

 
(30
)
Production
 
(3
)
 
—

 
—

 
(3
)
 
(40
)
 
(1
)
 
(10
)
 
(51
)
December 31, 2012
 
37

 
—

 
—

 
37

 
532

 
19

 
15

 
566

Revisions of previous estimates
 
14

 
—

 
—

 
14

 
5

 
7

 
2

 
14

Extensions, discoveries and other additions
 
22

 
—

 
—

 
22

 
78

 
—

 
2

 
80

Purchases of properties
 
—

 
—

 
—

 
—

 
2

 
—

 
—

 
2

Sales of properties
 
—

 
—

 
—

 
—

 
(1
)
 
—

 
—

 
(1
)
Production
 
(5
)
 
—

 
—

 
(5
)
 
(40
)
 
(1
)
 
(8
)
 
(49
)
December 31, 2013
 
68

 
—

 
—

 
68

 
576

 
25

 
11

 
612

Revisions of previous estimates
 
13

 
—

 
—

 
13

 
53

 
(2
)
 
—

 
51

Extensions, discoveries and other additions
 
12

 
—

 
—

 
12

 
71

 
1

 
—

 
72

Purchases of properties
 
1

 
—

 
—

 
1

 
9

 
—

 
—

 
9

Sales of properties
 
(9
)
 
—

 
—

 
(9
)
 
(39
)
 
—

 
(10
)
 
(49
)
Production
 
(9
)
 
—

 
—

 
(9
)
 
(48
)
 
(1
)
 
(1
)
 
(50
)
December 31, 2014
 
76

 
—

 
—

 
76

 
622

 
23

 
—

 
645

Proved developed reserves as of:
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
10

 
—

 
—

 
10

 
332

 
5

 
18

 
355

December 31, 2012
 
15

 
—

 
—

 
15

 
280

 
4

 
14

 
298

December 31, 2013
 
35

 
—

 
—

 
35

 
322

 
4

 
11

 
337

December 31, 2014
 
38

 
—

 
—

 
38

 
329

 
9

 
—

 
338

Proved undeveloped reserves as of:
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
6

 
—

 
—

 
6

 
276

 
15

 
6

 
297

December 31, 2012
 
22

 
—

 
—

 
22

 
252

 
15

 
1

 
268

December 31, 2013
 
33

 
—

 
—

 
33

 
254

 
21

 
—

 
275

December 31, 2014
 
38

 
—

 
—

 
38

 
293

 
14

 
—

 
307

 _________________
(1)
All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method. We used the economic interest method in Malaysia until we sold our Malaysia business in 2014.





112

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows: 
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China
 
Malaysia
 
Total
 
 
(In millions)
2014:
 
 
 
 
 
 
 
 
Future cash inflows
 
$
31,758


$
2,183


$
—


$
33,941

Less related future:
 







Production costs
 
(11,508
)

(784
)

—


(12,292
)
Development and abandonment costs
 
(4,611
)

(73
)

—


(4,684
)
Future net cash flows before income taxes
 
15,639


1,326


—


16,965

Future income tax expense
 
(4,449
)

(221
)

—


(4,670
)
Future net cash flows before 10% discount
 
11,190


1,105


—


12,295

10% annual discount for estimating timing of cash flows
 
(5,860
)

(223
)

—


(6,083
)
Standardized measure of discounted future net cash flows
 
$
5,330


$
882


$
—


$
6,212

 
 
 
 
 
 
 
 
 
2013:
 
 
 
 
 
 
 
 
Future cash inflows
 
$
26,600

 
$
2,640

 
$
1,245

 
$
30,485

Less related future:
 
 
 
 
 
 
 
 
Production costs
 
(8,302
)
 
(959
)
 
(771
)
 
(10,032
)
Development and abandonment costs
 
(4,166
)
 
(143
)
 
(148
)
 
(4,457
)
Future net cash flows before income taxes
 
14,132

 
1,538

 
326

 
15,996

Future income tax expense
 
(4,278
)
 
(316
)
 
—

 
(4,594
)
Future net cash flows before 10% discount
 
9,854

 
1,222

 
326

 
11,402

10% annual discount for estimating timing of cash flows
 
(5,226
)
 
(320
)
 
(23
)
 
(5,569
)
Standardized measure of discounted future net cash flows
 
$
4,628

 
$
902

 
$
303

 
$
5,833

 
 
 
 
 
 
 
 
 
2012:
 
 
 
 
 
 
 
 
Future cash inflows
 
$
21,724

 
$
2,186

 
$
1,754

 
$
25,664

Less related future:
 
 
 
 
 
 
 
 
Production costs
 
(7,042
)
 
(888
)
 
(1,135
)
 
(9,065
)
Development and abandonment costs
 
(3,949
)
 
(202
)
 
(82
)
 
(4,233
)
Future net cash flows before income taxes
 
10,733

 
1,096

 
537

 
12,366

Future income tax expense
 
(2,786
)
 
(239
)
 
(66
)
 
(3,091
)
Future net cash flows before 10% discount
 
7,947

 
857

 
471

 
9,275

10% annual discount for estimating timing of cash flows
 
(4,539
)
 
(245
)
 
(55
)
 
(4,839
)
Standardized measure of discounted future net cash flows
 
$
3,408

 
$
612

 
$
416

 
$
4,436

 

113

NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Set forth in the table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during each of the years in the three-year period ended December 31, 2014:
 
 
Continuing Operations
 
Discontinued Operations
 
 
 
 
Domestic
 
China
 
Malaysia
 
Total
 
 
(In millions)
2014:
 
 
 
 
 
 
 
 
Beginning of the period
 
$
4,628

 
$
902

 
$
303

 
$
5,833

Revisions of previous estimates:
 
 
 
 
 
 
 
 
Changes in prices and costs
 
(492
)
 
(119
)
 
(132
)
 
(743
)
Changes in quantities
 
784

 
(104
)
 
—

 
680

Changes in future development costs
 
253

 
(72
)
 
129

 
310

Previously estimated development costs incurred during the period
 
698

 
147

 
12

 
857

Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs
 
860

 
—

 
—

 
860

Purchases and sales of reserves in place, net
 
(171
)
 
—

 
(279
)
 
(450
)
Accretion of discount
 
655

 
114

 
19

 
788

Sales of oil and gas, net of production costs
 
(1,662
)
 
(21
)
 
(54
)
 
(1,737
)
Net change in income taxes
 
(383
)
 
51

 
—

 
(332
)
Production timing and other
 
160

 
(16
)
 
2

 
146

Net increase (decrease)
 
702

 
(20
)
 
(303
)
 
379

End of period
 
$
5,330

 
$
882

 
$
—

 
$
6,212

2013:
 
 
 
 
 
 
 
 
Beginning of the period
 
$
3,408

 
$
612

 
$
416

 
$
4,436

Revisions of previous estimates:
 
 
 
 
 
 
 
 
Changes in prices and costs
 
944

 
2

 
33

 
979

Changes in quantities
 
81

 
302

 
76

 
459

Changes in future development costs
 
(83
)
 
(50
)
 
(126
)
 
(259
)
Previously estimated development costs incurred during the period
 
549

 
130

 
79

 
758

Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs
 
1,012

 
—

 
49

 
1,061

Purchases and sales of reserves in place, net
 
13

 
—

 
—

 
13

Accretion of discount
 
470

 
82

 
33

 
585

Sales of oil and gas, net of production costs
 
(973
)
 
(46
)
 
(330
)
 
(1,349
)
Net change in income taxes
 
(815
)
 
(63
)
 
59

 
(819
)
Production timing and other
 
22

 
(67
)
 
14

 
(31
)
Net increase (decrease)
 
1,220

 
290

 
(113
)
 
1,397

End of period
 
$
4,628

 
$
902

 
$
303

 
$
5,833

2012:
 
 
 
 
 
 
 
 
Beginning of the period
 
$
4,724

 
$
565

 
$
692

 
$
5,981

Revisions of previous estimates:
 
 
 
 
 
 
 
 
Changes in prices and costs
 
(1,490
)
 
(24
)
 
(14
)
 
(1,528
)
Changes in quantities
 
(427
)
 
—

 
23

 
(404
)
Changes in future development costs
 
294

 
(2
)
 
(19
)
 
273

Previously estimated development costs incurred during the period
 
434

 
67

 
93

 
594

Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs
 
791

 
24

 
—

 
815

Purchases and sales of reserves in place, net
 
(758
)
 
—

 
—

 
(758
)
Accretion of discount
 
542

 
77

 
64

 
683

Sales of oil and gas, net of production costs
 
(1,129
)
 
(63
)
 
(439
)
 
(1,631
)
Net change in income taxes
 
650

 
4

 
119

 
773

Production timing and other
 
(223
)
 
(36
)
 
(103
)
 
(362
)
Net increase (decrease)
 
(1,316
)
 
47

 
(276
)
 
(1,545
)
End of period
 
$
3,408

 
$
612

 
$
416

 
$
4,436


114

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.
 
Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2014.

Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm

The information required to be furnished pursuant to this item is set forth under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” in Item 8 of this report.

Changes in Internal Control over Financial Reporting

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
Item 9B. Other Information

None.

PART III
 
Item 10.     Directors, Executive Officers and Corporate Governance

The information appearing under the headings “Proposal 1: Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance — Board of Directors” and “Corporate Governance — Audit Committee” in our proxy statement for our 2015 annual meeting of stockholders to be held on May 15, 2015 (the “2015 Proxy Statement”) and the information set forth under the heading “Executive Officers of the Registrant” in this report are incorporated herein by reference.

Corporate Code of Business Conduct and Ethics

We have adopted a corporate code of business conduct and ethics for directors, officers (including our principal executive officer, principal financial officer and controller or principal accounting officer) and employees. In addition, we have adopted a financial code of ethics applicable to our Chief Executive Officer, Chief Financial Officer and Controller or Chief Accounting Officer. Both of these codes are available under the “Corporate Governance — Overview” tab on our website at www.newfield.com.

We intend to satisfy the disclosure requirements of Item 5.05 of Form 8-K regarding any amendment to, or waiver of, a provision of the corporate code of business conduct and ethics or the financial code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller and relates to any element of the definition of code of ethics set forth in Item 406(b) of Regulation S-K by posting such information under the “Corporate Governance” tab of our website at www.newfield.com.

115

Item 11.     Executive Compensation

The information appearing in our 2015 Proxy Statement under the headings “Compensation & Management Development Committee Report” (which is furnished), “Executive Compensation,” “Non-Management Director Compensation” and “Compensation Committee Interlocks and Insider Participation” is incorporated herein by reference.
 
Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information appearing in our 2015 Proxy Statement under the headings “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information” is incorporated herein by reference.
 
Item 13.     Certain Relationships and Related Transactions, and Director Independence

The information appearing in our 2015 Proxy Statement under the headings “Corporate Governance — Board of Directors” and “Interests of Management and Others in Certain Transactions” is incorporated herein by reference.
 
Item 14.     Principal Accounting Fees and Services

The information appearing in our 2015 Proxy Statement under the heading “Principal Accounting Fees and Services” is incorporated herein by reference.


116

PART IV
 
Item 15.     Exhibits and Financial Statement Schedules

Financial Statements

Reference is made to the table of contents set forth on page 64 of this report.

Financial Statement Schedules

Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements.

Exhibits
Exhibit
Number
 
Title
3.1
—
Third Restated Certificate of Incorporation of Newfield dated December 14, 2011 (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
 
 
 
3.2
—
Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on July 25, 2013 (File No. 1-12534))
 
 
 
4.1
—
Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly 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
—
First Supplemental Indenture, dated as of February 19, 2010, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 19, 2010 (File No. 1-12534))
 
 
 
4.1.2
—
Second Supplemental Indenture, dated as of September 30, 2011, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to 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))
 
 
 
4.1.3
—
Third Supplemental Indenture, dated as of June 26, 2012, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to 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))
 
 
 
4.2
—
Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly 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 (Registration No. 333-71348))
 
 
 
4.2.1
—
Second Supplemental Indenture, dated as of August 18, 2004, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.6.3 to Newfield’s Registration Statement on Form S-4 filed with the SEC on January 19, 2005 (Registration No. 333-122157))
 
 
 
4.2.2
—
Third Supplemental Indenture, dated as of April 3, 2006, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.4.3 to Newfield’s Current Report on Form 8-K filed with the SEC on April 3, 2006 (File No. 1-12534))
 
 
 

117

4.2.3
—
Fourth Supplemental Indenture, dated as of May 8, 2008, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on May 7, 2008 (File No. 1-12534))
 
 
 
4.2.4
—
Fifth Supplemental Indenture, dated as of January 25, 2010, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on January 26, 2010 (File No. 1-12534))
 
 
 
4.2.5
—
Sixth Supplemental Indenture, dated as of July 3, 2012, to the Subordinated Indenture dated as of December 10, 2001, between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 3, 2012 (File No. 1-12534))
 
 
 
†10.1
—
Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.7.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-12534))
 
 
 
†10.1.1
—
First Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.3 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
 
 
 
†10.1.2
—
Second Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 99.3 to Newfield’s Current Report on Form 8-K filed with the SEC on May 5, 2005 (File No. 1-12534))
 
 
 
†10.2
—
Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K/A filed with the SEC on March 1, 2007 (File No. 1-12534))
 
 
 
†10.2.1
—
First Amendment to Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.4.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-12534))
 
 
 
†10.3
—
Newfield Exploration Company 2009 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 4, 2009 (Registration No. 333-158961))
 
 
 
†10.4
—
Form of 2008 Stock Option Agreement between Newfield and each of Lee K. Boothby, Michael Van Horn, George T. Dunn, John H. Jasek, Gary D. Packer, James T. Zernell, Stephen C. Campbell, John D. Marziotti, Susan G. Riggs and Daryll T. Howard dated as of February 7, 2008 (incorporated by reference to Exhibit 10.3 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2008 (File No. 1-12534))
 
 
 
†10.5
—
Form of Restricted Stock Agreement dated as of February 4, 2009 between Newfield and its executive officers (incorporated by reference to Exhibit 10.15 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))
 
 
 
†10.6
—
Form of Restricted Stock Agreement between Newfield and each of Lee K. Boothby and Gary D. Packer dated as of May 7, 2009 (incorporated by reference to Exhibit 10.24 to Newfield’s Current Report on Form 8-K filed with the SEC on May 11, 2009 (File No. 1-12534))
 
 
 
†10.7
—
Form of 2010 TSR Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.20 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
 
 
 

118

†10.8
—
Form of 2010 Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.21 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
 
 
 
†10.9
—
Summary of Non-Employee Director Compensation Program (incorporated by reference to Exhibit 10.14 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
 
 
 
†10.10
—
Second Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 (File No. 1-12534))
 
 
 
†10.11
—
Newfield Exploration Company 2011 Annual Incentive 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))
 
 
 
†10.12
—
Newfield Exploration Company Deferred Compensation Plan as Amended and Restated as of November 6, 2008 (incorporated by reference to Exhibit 10.17.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 10, 2008 (File No. 1-12534))
 
 
 
†10.12.1
—
Amendment No. 1 to Newfield Exploration Company Deferred Compensation Plan and its related Non-Qualified Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 14, 2012 (File No. 1-12534))
 
 
 
†10.13
—
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))
 
 
 
†10.14
—
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))
 
 
 
†10.15
—
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))
 
 
 
†10.16
—
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))
 
 
 
†10.17
—
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))
 
 
 
†10.18
—
Form of 2011 Executive Officer Restricted Stock Unit Award Agreement under 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, 2011 (File No. 1-12534))
 
 
 
†10.19
—
Form of 2011 Executive Officer TSR Restricted Stock Unit Award Agreement under 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, 2011 (File No. 1-12534))
 
 
 
†10.20
—
Form of 2012 Executive Officer Restricted Stock Unit Award Agreement Under 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, 2012 (File No. 1-12534))

119

 
 
 
†10.21
—
Form of 2012 Executive Officer TSR Restricted Stock Unit Award Agreement Under 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, 2012 (File No. 1-12534))
 
 
 
†10.22
—
Newfield Exploration Company 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 (Registration No. 333-173964))
 
 
 
†10.22.1
—
Newfield Exploration Company Amended and Restated 2011 Omnibus Stock Plan (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))
 
 
 
†10.23
—
Form of Non-Employee Director Restricted Stock Award Agreement under 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 June 30, 2011 (File No. 1-12534))
 
 
 
†10.24
—
Form of 2013 Executive Officer Restricted Stock Unit Award Agreement under 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, 2013 (File No. 1-12534))
 
 
 
†10.25
—
Form of 2013 Executive Officer TSR Restricted Stock Unit Award Agreement under 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, 2013 (File No. 1-12534))
 
 
 
†10.26
—
Form of 2014 Cash-Settled Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.3 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
 
 
 
†10.27
—
Form of 2014 Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
 
 
 
†10.28
—
Amended Form of 2014 Executive Officer TSR Restricted Stock Unit Award Agreement under 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, 2014 (File No. 1-12534))
 
 
 
†10.29
—
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))
 
 
 
†10.29.1
—
Amendment No. 1 to the Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.1to Newfield's Current Report on Form 8-K filed with the SEC on February 11, 2014 (File No. 1-12534))
 
 
 
10.30
—
Credit Agreement, dated as of June 2, 2011, by and among Newfield 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, and other Lenders thereto (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))
 
 
 

120

10.30.1
—
First Amendment to Credit Agreement, dated as of September 27, 2011, by and among Newfield 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, and other Lenders 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))
 
 
 
10.30.2
—
Second Amendment to Credit Agreement, dated as of April 29, 2013, by and among Newfield 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 Co-Documentation Agents, and other Lenders 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))
 
 
 
10.30.3
—
Third Amendment to Credit Agreement, dated as of June 25, 2013, by and among Newfield 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 Co-Documentation Agents, and other Lenders thereto (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))
 
 
 
10.31
—
Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of October 22, 2013 (incorporated by reference to Exhibit 2.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
 
 
 
10.31.1
—
Amendment to Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of February 9, 2014 (incorporated by reference to Exhibit 2.2 to Newfield's Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
 
 
 
†10.32
—
Retirement Agreement of Terry W. Rathert (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on August 29, 2014 (File No. 1-12535))
 
 
 
†10.33
—
Form of Change of Control Severance Agreement by and between the Company and Lawrence S. Massaro (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on December 23, 2014 (File No. 1-12535))
 
 
 
*21.1
—
List of Significant Subsidiaries
 
 
 
*23.1
—
Consent of PricewaterhouseCoopers LLP
 
 
 
*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
 
 
 

121

*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.

122

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 24th day of February 2015. 
NEWFIELD EXPLORATION COMPANY
 
 
By:
 
/s/    LEE K. BOOTHBY        
 
 
Lee K. Boothby
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 24th day of February 2015.
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 and Assistant Corporate Secretary
George W. Fairchild, Jr.
 
(Principal Accounting Officer)
 
 
 
 
/S/    PAMELA J. GARDNER*
 
Director
Pamela J. Gardner
 
 
 
 
 
 
/S/    JOHN R. KEMP III*        
 
Director
John R. Kemp III
 
 
 
 
 
 
/S/    STEVEN W. NANCE*        
 
Director
Steven W. Nance
 
 
 
 
 
 
/S/    HOWARD H. NEWMAN*        
 
Director
Howard H. Newman
 
 
 
 
 
 
/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/    C. E. SHULTZ*        
 
Director
C. E. Shultz
 
 
 
 
 
 
/S/    RICHARD K. STONEBURNER*        
 
Director
Richard K. Stoneburner
 
 
 
 
 
 
/S/    J. TERRY STRANGE*        
 
Director
J. Terry Strange
 
 
 
 
 
 
*By: 
    /s/    GEORGE  W. FAIRCHILD, JR.    
 
 
 
George W. Fairchild, Jr.
as Attorney-in-Fact
 
 


123

EXHIBIT INDEX

Exhibit
Number
 
Title
3.1
—
Third Restated Certificate of Incorporation of Newfield dated December 14, 2011 (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
 
 
 
3.2
—
Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on July 25, 2013 (File No. 1-12534))
 
 
 
4.1
—
Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly 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
—
First Supplemental Indenture, dated as of February 19, 2010, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 19, 2010 (File No. 1-12534))
 
 
 
4.1.2
—
Second Supplemental Indenture, dated as of September 30, 2011, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to 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))
 
 
 
4.1.3
—
Third Supplemental Indenture, dated as of June 26, 2012, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to 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))
 
 
 
4.2
—
Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly 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 (Registration No. 333-71348))
 
 
 
4.2.1
—
Second Supplemental Indenture, dated as of August 18, 2004, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.6.3 to Newfield’s Registration Statement on Form S-4 filed with the SEC on January 19, 2005 (Registration No. 333-122157))
 
 
 
4.2.2
—
Third Supplemental Indenture, dated as of April 3, 2006, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.4.3 to Newfield’s Current Report on Form 8-K filed with the SEC on April 3, 2006 (File No. 1-12534))
 
 
 
4.2.3
—
Fourth Supplemental Indenture, dated as of May 8, 2008, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on May 7, 2008 (File No. 1-12534))
 
 
 
4.2.4
—
Fifth Supplemental Indenture, dated as of January 25, 2010, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on January 26, 2010 (File No. 1-12534))
 
 
 

124

4.2.5
—
Sixth Supplemental Indenture, dated as of July 3, 2012, to the Subordinated Indenture dated as of December 10, 2001, between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 3, 2012 (File No. 1-12534))
 
 
 
†10.1
—
Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.7.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-12534))
 
 
 
†10.1.1
—
First Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.3 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
 
 
 
†10.1.2
—
Second Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 99.3 to Newfield’s Current Report on Form 8-K filed with the SEC on May 5, 2005 (File No. 1-12534))
 
 
 
†10.2
—
Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K/A filed with the SEC on March 1, 2007 (File No. 1-12534))
 
 
 
†10.2.1
—
First Amendment to Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.4.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-12534))
 
 
 
†10.3
—
Newfield Exploration Company 2009 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 4, 2009 (Registration No. 333-158961))
 
 
 
†10.4
—
Form of 2008 Stock Option Agreement between Newfield and each of Lee K. Boothby, Michael Van Horn, George T. Dunn, John H. Jasek, Gary D. Packer, James T. Zernell, Stephen C. Campbell, John D. Marziotti, Susan G. Riggs and Daryll T. Howard dated as of February 7, 2008 (incorporated by reference to Exhibit 10.3 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2008 (File No. 1-12534))
 
 
 
†10.5
—
Form of Restricted Stock Agreement dated as of February 4, 2009 between Newfield and its executive officers (incorporated by reference to Exhibit 10.15 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))
 
 
 
†10.6
—
Form of Restricted Stock Agreement between Newfield and each of Lee K. Boothby and Gary D. Packer dated as of May 7, 2009 (incorporated by reference to Exhibit 10.24 to Newfield’s Current Report on Form 8-K filed with the SEC on May 11, 2009 (File No. 1-12534))
 
 
 
†10.7
—
Form of 2010 TSR Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.20 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
 
 
 
†10.8
—
Form of 2010 Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.21 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
 
 
 
†10.9
—
Summary of Non-Employee Director Compensation Program (incorporated by reference to Exhibit 10.14 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
 
 
 

125

†10.10
—
Second Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 (File No. 1-12534))
 
 
 
†10.11
—
Newfield Exploration Company 2011 Annual Incentive 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))
 
 
 
†10.12
—
Newfield Exploration Company Deferred Compensation Plan as Amended and Restated as of November 6, 2008 (incorporated by reference to Exhibit 10.17.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 10, 2008 (File No. 1-12534))
 
 
 
†10.12.1
—
Amendment No. 1 to Newfield Exploration Company Deferred Compensation Plan and its related Non-Qualified Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 14, 2012 (File No. 1-12534))
 
 
 
†10.13
—
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))
 
 
 
†10.14
—
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))
 
 
 
†10.15
—
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))
 
 
 
†10.16
—
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))
 
 
 
†10.17
—
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))
 
 
 
†10.18
—
Form of 2011 Executive Officer Restricted Stock Unit Award Agreement under 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, 2011 (File No. 1-12534))
 
 
 
†10.19
—
Form of 2011 Executive Officer TSR Restricted Stock Unit Award Agreement under 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, 2011 (File No. 1-12534))
 
 
 
†10.20
—
Form of 2012 Executive Officer Restricted Stock Unit Award Agreement Under 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, 2012 (File No. 1-12534))
 
 
 
†10.21
—
Form of 2012 Executive Officer TSR Restricted Stock Unit Award Agreement Under 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, 2012 (File No. 1-12534))
 
 
 
†10.22
—
Newfield Exploration Company 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 (Registration No. 333-173964))

126

 
 
 
†10.22.1
—
Newfield Exploration Company Amended and Restated 2011 Omnibus Stock Plan (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))
 
 
 
†10.23
—
Form of Non-Employee Director Restricted Stock Award Agreement under 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 June 30, 2011 (File No. 1-12534))
 
 
 
†10.24
—
Form of 2013 Executive Officer Restricted Stock Unit Award Agreement under 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, 2013 (File No. 1-12534))
 
 
 
†10.25
—
Form of 2013 Executive Officer TSR Restricted Stock Unit Award Agreement under 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, 2013 (File No. 1-12534))
 
 
 
†10.26
—
Form of 2014 Cash-Settled Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.3 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
 
 
 
†10.27
—
Form of 2014 Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
 
 
 
†10.28
—
Amended Form of 2014 Executive Officer TSR Restricted Stock Unit Award Agreement under 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, 2014 (File No. 1-12534))
 
 
 
†10.29
—
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))
 
 
 
†10.29.1
—
Amendment No. 1 to the Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.1to Newfield's Current Report on Form 8-K filed with the SEC on February 11, 2014 (File No. 1-12534))
 
 
 
10.30
—
Credit Agreement, dated as of June 2, 2011, by and among Newfield 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, and other Lenders thereto (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))
 
 
 
10.30.1
—
First Amendment to Credit Agreement, dated as of September 27, 2011, by and among Newfield 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, and other Lenders 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))
 
 
 
10.30.2
—
Second Amendment to Credit Agreement, dated as of April 29, 2013, by and among Newfield 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 Co-Documentation Agents, and other Lenders 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))

127

 
 
 
10.30.3
—
Third Amendment to Credit Agreement, dated as of June 25, 2013, by and among Newfield 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 Co-Documentation Agents, and other Lenders thereto (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))
 
 
 
10.31
—
Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of October 22, 2013 (incorporated by reference to Exhibit 2.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
 
 
 
10.31.1
—
Amendment to Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of February 9, 2014 (incorporated by reference to Exhibit 2.2 to Newfield's Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
 
 
 
†10.32
—
Retirement Agreement of Terry W. Rathert (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on August 29, 2014 (File No. 1-12535))
 
 
 
†10.33
—
Form of Change of Control Severance Agreement by and between the Company and Lawrence S. Massaro (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on December 23, 2014 (File No. 1-12535))
 
 
 
*21.1
—
List of Significant Subsidiaries
 
 
 
*23.1
—
Consent of PricewaterhouseCoopers LLP
 
 
 
*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
 
 
 
*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
 
 
 

128

*101.DEF
—
XBRL Definition Linkbase Document
_________________
*
Filed or furnished herewith.
†
Identifies management contracts and compensatory plans or arrangements.


129