General

Newfield Exploration Company, a Delaware corporation formed in 1988, is an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. During 2013, a decision was made to focus on our principal domestic areas of operation, which include the Mid-Continent, the Rocky Mountains and onshore Gulf Coast. During 2013, our international businesses in Malaysia and China were held for sale and reported as "discontinued operations." In early February 2014, we closed the sale of our Malaysian business for approximately $898 million. We are still in the process of selling our offshore China business.

Through our website, www.newfield.com , you can access, free of charge, electronic copies of our governing documents, including our Board of Directors’ Corporate Governance Principles and the charters of the committees of our Board of Directors. In addition, you can access through our website 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 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.

Our Business Strategy

In 2013, we celebrated our 25th year as a company. We have adapted our focus areas and business strategies through the years to effectively compete within our industry and remain profitable. Today, our overarching business strategy is to deliver long-term stockholder value through safely, ethically and profitably exploring for, acquiring and developing North American oil and gas resource plays. Over the last five years, we have refined our asset base and focused on creating value through liquids investments. Today, we have a diversified asset portfolio capable of sustainable growth. Our core strategy consists of the following key elements:

Maintaining a Diversified Portfolio of Core North American Assets.      Over the last several years, we have transitioned from a conventional, natural gas company to an unconventional company focused on North American liquids-rich resource plays. By maintaining a diverse asset portfolio, we increase our flexibility to respond, and limit our exposure, to the volatility and unique risks our industry faces, such as geologic risks, geographic risks and commodity price risks. In line with this element of our strategy and the continued weakness in natural gas prices, our 2014 plans include:

Maintaining a Strong Capital Structure.     Maintaining a strong capital structure is central to our strategy. A strong balance sheet preserves financial flexibility and helps ensure that we maintain sufficient liquidity to implement our overall business strategy. In line with this element of our strategy, our 2014 plans include:

Growing Through a Combination of Development Drilling and Select Acquisitions .    Throughout our 25-year history, our growth has come from a combination of select acquisitions and exploration and exploitation drilling. We develop resources in our focus areas while continually looking for new opportunities in and around these areas. To manage risks associated with our strategy to grow reserves through drilling, substantially all of the domestic wells we drilled in 2013 had low geologic risk. Since 2000, we have completed several acquisitions that led to the expansion of our operating areas or the establishment of focus areas onshore in the United States. In 2013, we acquired about 65,000 net acres in Oklahoma's Anadarko Basin "STACK" play. This recent acquisition complemented our growing position in the basin's prolific Cana Woodford play, which was largely leased in 2011 and 2012. In 2011, we acquired approximately 65,000 net acres in the Uinta Basin, which fit well with our existing properties in the basin. We are focused on distinct geographic regions and geologic plays where we can leverage our experience and core competencies. In line with these elements of our strategy, our 2014 plans include:

Operating our Assets and Improving Operational Efficiencies.     We prefer to operate our properties. By controlling operations, we can better manage the timing of their development and production, control operating expenses and capital investments, ensure the appropriate application of technologies and promote safety and corporate responsibility. We operate a significant portion of our total net production and believe that improving operational efficiencies requires extensive knowledge of the geologic and operating conditions in the areas where we operate. Therefore, we focus our efforts on a limited number of geographic areas where our core competencies provide a competitive advantage and can positively influence operational efficiencies. Geographic focus allows for the more efficient use of both our capital and human resources. In line with this element of our strategy, our 2014 plans include:

Attracting and Retaining Quality Employees and Ensuring Their Interests are Aligned with our Stockholders’ Interests .     We believe in hiring top-tier talent and are committed to our employees' education and development. We believe that employees should be rewarded for their performance and that their interests should be aligned with our stockholders’ interests. As a result, we reward and encourage our employees through performance-based compensation and equity-based ownership.

2014 Outlook and Planned Capital Investments

Our strategy is to focus on North American resource plays, and we plan to invest $1.6 billion (excluding capitalized internal costs) to these activities in 2014. In early February 2014, we closed the sale of our Malaysian business for approximately $898 million and are continuing to take steps to sell our offshore China business. Depending on the timing of the sale for our China business, we intend to invest approximately $100 million in China in 2014. Our 2014 investments will be financed through our cash flows from operations, proceeds from our recent Malaysian sale and the use of our credit facility.

 

Our domestic liquids production is expected to grow approximately 30% in 2014 . As a result of reduced investments over the last several years, our natural gas assets have experienced natural declines. In 2014 , we expect our gas volumes to be consistent with the prior year. Combined, we expect our 2014 production from continuing operations to range from 44 – 48 MMBOE, or about 16% higher than 2013 domestic volumes.

Approximately 89% of our expected 2014 domestic oil and gas production is hedged against future changes in commodity prices. For a complete discussion of our hedging activities, a list of open contracts as of December 31, 2013 and the estimated fair value of those contracts as of that date, see Note 5, “Derivative Financial Instruments,” to our consolidated financial statements.

Our Properties and Plans for 2014

Our strategic focus is on North American resource plays. Our domestic plays represent approximately 94% of our proved reserves at year-end 2013.

Mid-Continent.     Approximately 45% of our proved reserves are located in our Mid-Continent region. We have more than a decade of experience developing the Woodford Shale. Our acreage includes more than 400,000 net acres in the region, which includes positions in the dry gas Arkoma Basin Woodford and the liquids-rich Cana Woodford in the Anadarko Basin. Our position in the Anadarko Basin was assembled over the last three years.

Anadarko Basin.     We have about 225,000 net acres that are prospective for development in the Anadarko Basin. As of February 2014, we had drilled approximately 75 wells in the Anadarko Basin, with wells yielding high volumes of oil and natural gas liquids. For 2014, we have allocated approximately $700 million, or double our previous year's investment, to drilling in our SCOOP (located in South Central Oklahoma) and STACK plays in the Anadarko Basin. We are planning to operate eight rigs throughout the year. At year-end 2013, our production was approximately 25,000 BOEPD, consisting of 6,600 BOPD, 7,050 BOEPD of NGLs and 67 MMcf/d.

Arkoma Basin.     We have significant dry gas production from the Arkoma Basin. The area represents approximately 20% of our total consolidated proved reserves. Our investment levels in this area have been significantly curtailed over the last four years due to low natural gas prices. As of December 31, 2013, we had approximately 150,000 net acres in the Arkoma Basin and our net production was approximately 21,700 BOEPD, consisting of 140 BOPD, 190 BOEPD of NGLs and 128 MMcf/d. Our production in this area is on natural decline. Substantially all of our acreage in this region is held-by-production.

Granite Wash.     We have approximately 45,000 net acres prospective for development in the Granite Wash, located in the Anadarko Basin of northern Texas and western Oklahoma. Our largest producing field in the Granite Wash is Stiles/Britt Ranch. At year-end 2013, our net production from the area was approximately 13,300 BOEPD, consisting of 1,400 BOPD, 3,700 BOEPD of NGLs and 49 MMcf/d.

Rocky Mountains.     We are actively assessing and developing more than 300,000 net acres in the Rocky Mountain region. Our assets are primarily oil and characterized by long-lived production. Our 2014 efforts are focused primarily in the Uinta and Williston basins.

Uinta Basin.     About 26% of our proved reserves are located in the 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.

We entered the Uinta Basin through a 2004 acquisition of the Greater Monument Butte Unit, a large waterflood field. Since that time, we have drilled approximately 1,700 wells in the unit and today have approximately 1,300 productive oil wells and approximately 1,100 water injection wells. The primary producing horizon in the unit is the Green River. Through an acquisition in 2011, we expanded our footprint in the area and today have more than 140,000 prospective net acres outside the GMBU. We have been exploring deeper geologic horizons on this acreage, including the Uteland Butte and Wasatch formations.

We have allocated approximately $400 million to our Uinta Basin programs in 2014, of which nearly half is expected to be allocated to the Central Basin. Our net production from the Uinta Basin at year-end 2013 was approximately 24,250 BOEPD, comprised of 19,200 BOPD, 950 BOEPD of NGLs and 25 MMcf/d. To date, we have drilled approximately 80 wells in these plays and plan to drill approximately 15 wells to test the Uteland Butte and Wasatch formations in 2014. Our 2014 production in the Uinta Basin is expected to increase about 5% over 2013 levels.

Williston Basin.     We have approximately 100,000 net acres in the Williston Basin, of which 41,000 acres are being actively developed in the Bakken and Three Forks plays of North Dakota. Our activities today are largely development focused and we are drilling multi-well pads with lateral lengths as long as 10,000 feet. Our net production at year-end 2013 was approximately 13,600 BOEPD, comprised of 10,500 BOPD, 1,300 BOEPD of NGLs and 11 MMcf/d. We have allocated approximately $330 million to our Williston Basin developments and plan to operate four rigs throughout the year, which is consistent with our 2013 activity levels. We expect our production from the Williston Basin to increase about 40% over 2013 levels.

Onshore Gulf Coast.     We have approximately 160,000 net acres in the Maverick Basin, of which we believe approximately 25,000 net acres are prospective for development. Our acreage is located primarily in the Maverick Basin of Maverick, Dimmit and Zavala counties, Texas. To date, we have completed more than 100 wells in the basin. We expect to operate one rig in the area in 2014 to drill about 20 wells. Our development is focused on pad drilling with lateral lengths of at least 7,500 feet. Our planned capital investments for 2014 are approximately $170 million. At year-end 2013, our net daily production in the Eagle Ford was approximately 11,800 BOEPD, consisting of 6,800 BOPD, 2,600 BOEPD of NGLs and 15 MMcf/d, and production is expected to grow 30% over 2013 levels.

Over the last several years, we have slowed our activities in many of our conventional natural gas plays and sold certain non-strategic assets. The proceeds from these asset sales have been invested in our unconventional resource plays. As of December 31, 2013, we owned an interest in approximately 109,000 net acres in conventional onshore plays. At year-end 2013, our net production was approximately 6,800 BOEPD, consisting of 360 BOPD, 300 BOEPD of NGLs and 37 MMcf/d, from our conventional onshore Texas assets. We expect our production in these conventional plays to continue to experience natural declines in 2014 due to limited investment.

Reserves

At year-end 2013 , we had proved reserves from continuing operations of 576 MMBOE, 8% higher than year-end 2012 . Proved reserves at year-end 2013 associated with discontinued operations were 36 MMBOE, 4% higher than year-end 2012. Highlights from our year-end 2013 proved reserves report include:

• domestic proved developed reserves increased 15% over 2012;

• 56% of domestic reserves are proved developed;

• domestic reserves account for 94% of our total proved reserves; and

The table below summarizes our proved reserves by area at December 31, 2013.

		Proved Reserves			Percentage of Proved Reserves
		(In MMBOE)
Continuing operations:
Onshore Gulf Coast		51			8	%
Mid-Continent		275			45	%
Rocky Mountains		250			41	%
Total continuing operations		576			94	%
Discontinued operations:
International		36			6	%
Total		612			100	%

 

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 (those whose reserves are greater than 15% of our total proved reserves), which are the GMBU, Arkoma Woodford Shale and SCOOP. For a discussion regarding our total domestic and international annual production volumes, average realized prices, related cost structure and information about delivery commitments, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations, ” which disclosure is incorporated herein by reference.

Estimated 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 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 infill 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. Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves and future net cash flows and discounted future net cash flows from proved reserves at December 31, 2013 , 2012 and 2011 , as well as changes in proved reserves during the last three years, are contained in “Supplementary Financial Information — Supplementary Oil and Gas Disclosures” in Item 8 of this report.

The following table shows by country and in the aggregate a summary of our proved oil and gas reserves as of December 31, 2013 .

Proved Reserves.     Our year-end 2013 proved reserves of 612 MMBOE increased 8% compared to our proved reserves at year-end 2012 . Our reserves consisted of 282 MMBOE proved developed producing, 55 MMBOE proved developed non-producing and 275 MMBOE proved undeveloped reserves. Our proved liquids reserves at year-end 2013 were 338 million barrels, compared to 274 million barrels at year-end 2012 , an increase of 23%. During 2013, oil and condensate reserves increased 33 million barrels and NGL reserves increased 31 million barrels. At year-end 2013, 80% of our proved liquids reserves were crude oil or condensate. At December 31, 2013 , our proved natural gas reserves were 1,648 Bcf which represented a decrease of 6% compared to 2012 .

During 2013, we added 80 MMBOE through discoveries, extensions and other additions. Consistent with our continued focus on domestic liquids, our 2013 additions were 98% domestic and 61% were liquids, which was 27 million barrels of oil and 22 million barrels of NGLs. Through infill drilling revisions, we added 75 MMBOE. At December 31, 2013 , the SEC pricing for natural gas was $ 3.67 per MMBtu, a 33% increase compared to the prior year-end. As a result, we revised our total proved reserves upward by 10 MMBOE. However, consistent with our domestic liquids focus we removed 294 Bcf of natural gas reserves because we do not expect to drill them within the next five years. During 2013, we had a negative 24 MMBOE performance revision, 90% of the revision was in natural gas and primarily associated with the Uinta Basin.

Proved Undeveloped Reserves.      Our proved undeveloped reserves at December 31, 2013 were 275 MMBOE compared to 268 MMBOE at December 31, 2012 . Liquids comprised 64% of our total proved undeveloped reserves as of December 31, 2013 . During 2013 , we invested approximately $0.7 billion of drilling, completion and facilities-related capital to convert 32 MMBOE of our December 31, 2012 proved undeveloped reserves into proved developed reserves. Additionally, we invested approximately $0.1 billion of facilities-related capital for the continued development of our proved undeveloped reserves that were not fully converted to proved developed status as of December 31, 2013 . Through infill drilling revisions, we added 41 MMBOE. During 2013 , we added 54 MMBOE of new proved undeveloped reserves through discoveries, extensions and other additions, a 1 MMBOE net increase due to sales and acquisitions, and negative revisions of 62 MMBOE primarily driven by increased focus on liquids delaying the development of 49 MMBOE of gas reserves in the next five years.

Proved undeveloped reserve quantities are limited by the activity level of development drilling we expect to undertake during the 2014 - 2018 five-year period. Of the 275 MMBOE of proved undeveloped reserves at December 31, 2013, 29 MMBOE is associated with the Greater Monument Butte waterflood and are currently planned to be developed within the next five years, but exceed five years from the date of first booking. The waterflood requires the timely and orderly drilling of production and 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. The scope and scale of this project is such that if it were terminated, for whatever reason, a significant portion of previously invested capital would be lost. For additional information regarding the changes in our proved reserves, see our "Supplementary Oil and Gas Disclosures" under Item 8 of this report.

In the years 2011 through 2013 , we developed 19%, 9% and 12%, 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.

Reserves Sensitivities

To determine our year-end 2013 reserve estimates, we utilized SEC pricing for natural gas of $3.67 per MMBtu and crude oil of $ 96.82 per barrel.

Using crude oil prices of $80 and $90 per barrel, the quantity of our domestic proved developed reserves decreases by 1% and 0% respectively, due to shortening of the economic life. Our proved undeveloped liquids reserves are primarily in the Uinta Basin of Utah, the Williston Basin of North Dakota and the Anadarko Basin of Oklahoma. At crude oil prices of $80 per barrel, and without a commensurate change in cost, our domestic proved undeveloped reserves would decrease by approximately 9 MMBOE, and we would reduce our future capital investment by a total of approximately $250 million during the next five years. As a result of the foregoing, at $80 per barrel our domestic proved reserves would decrease by 2%.

Our planned capital activity focuses on liquids versus natural gas and is limited by the level of development drilling we expect to undertake in the future. At natural gas prices below $3.00 per MMBtu, our domestic proved developed reserves

would decrease by 2% due to shortening the economic life. In line with our liquids focus, at the lower gas prices our undeveloped reserves remain materially unchanged. At higher natural gas prices of $4.00 and $5.00 per MMBtu, and without reconfiguring to optimize our development plan, the pre-tax present value of our proved reserves would increase by $223 million and $902 million, respectively.

Under the terms of our production sharing contracts (PSC) in Malaysia and China, an increase or decrease in realized oil prices would result in a decrease or increase, respectively, in our proved reserves. At higher oil prices, lesser quantities of oil are required for cost recovery and at lower oil prices, greater quantities of oil are required for cost recovery. Our share (the contractor’s share) of future production is impacted accordingly. The effect of higher or lower oil prices may be partially offset by extending or shortening, respectively, the economic life of proved reserves.

We were in the process of drilling 16 gross (13.1 net) development wells domestically at December 31, 2013. Internationally, we were drilling 1 gross (0.4 net) exploitation well in Malaysia at December 31, 2013.

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. Generally, an operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates established by the various operating agreements or contracts. The charges customarily vary with the depth and location of the well being operated.

Acreage Data

The following two tables list by geographic area interests we owned in developed and undeveloped oil and gas acreage at December 31, 2013, 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, which are now classified as discontinued operations, are offshore and generally arise from participation in PSCs.