Newfield Exploration Company (NFX)

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

 

Commission file number: 1-12534

 

Newfield Exploration Company

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:

281-847-6000

 

Securities registered Pursuant to Section 12(b) of the Act:

 

 

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 o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.  Yes o     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 o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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.  o

 

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):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $6 billion as of June 30, 2007 (based on the last sale price of such stock as quoted on the New York Stock Exchange).

 

As of February 25, 2008, there were 131,496,126 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

 

Documents incorporated by reference: Proxy Statement of Newfield Exploration Company for the Annual Meeting of Stockholders to be held May 1, 2008, which is incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

 

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 Item 7 of this report. Unless the context otherwise requires, all references in this report to “Newfield,” “we,” “us” or “our” 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.

 

PART I

 

 

We are an independent oil and gas company engaged in the exploration, development and acquisition of natural gas and crude oil properties. Our domestic areas of operation include the Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of Mexico. Internationally, we are active in Malaysia and China.

 

General information about us can be found at www.newfield.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them. Information contained at our website is not incorporated by reference into this report and you should not consider information contained at our website as part of this report.

Overview

 

Our company was founded in 1989. For the first 10 years of our existence, we focused on the shallow waters of the Gulf of Mexico. In the late-1990s, we began to expand our operations into other regions to gain access to properties and opportunities necessary for our continued growth. Cash flows from our Gulf of Mexico operations funded this expansion. Today, our asset base and related capital programs are diversified both geographically and by type — offshore and onshore, domestic and international, conventional plays and unconventional “resource” plays, a large inventory of low risk exploitation and development opportunities and a smaller, but significant, inventory of higher risk, higher reserve potential exploration opportunities.

 

At year-end 2007, we had proved reserves of 2.5 Tcfe. Those reserves were 73% natural gas and 63% proved developed. As a result of our focus on unconventional “resource” plays in the Rocky Mountains and Mid-Continent and the sale of our shallow water Gulf of Mexico assets in August 2007, our reserve life index is now more than 10 years. Of our year-end 2007 reserves:

 

 

By geographical region, we expect the sources of our 2008 budgeted production will be:

 

Increased Focus on “Resource” Plays

 

In part, the changes in our asset base are reflective of broader trends underway in our industry. As the traditional producing basins in the U.S. have matured, exploration and production has shifted to unconventional “resource” plays. Resource plays typically cover expansive areas, provide multi-year inventories of drilling opportunities and have sustainable lower risk growth profiles. The economics of these plays rely on technological advances, hands on experience, repeatability and strong commodity prices. Today, we have two large resource plays — the Woodford Shale and Monument Butte — and are active in several other plays.

 

Mid-Continent.  Our largest single investment area over the last two years has been the Woodford Shale play, located in the Arkoma Basin of southeast Oklahoma. Our activities began in this area in 2003, and our early success in drilling led to the leasing of approximately 165,000 net acres. Since 2003, we have drilled more than 100 vertical wells and 160 horizontal wells to delineate our acreage position. The Woodford formation is a shale interval that varies in thickness from 100–200 feet throughout our acreage. At year-end 2007, our production was 165 MMcfe/d gross. The field has thousands of drilling locations. Our efforts are focused primarily on determining the appropriate spacing for our development wells. In 2008, we will drill pilots on both 40- and 80-acre spacing.

 

In addition to the Woodford Shale, our activities in the Mid-Continent are focused on the Mountain Front Wash play in the Anadarko Basin. Our production there reached a record level of 97 MMcfe/d in early 2008. Our largest producing field in the play is Stiles Ranch, where our working interest is predominately 100%.

 

Monument Butte.  In August 2004, we purchased the giant Monument Butte oil field, located in the Uinta Basin of northeastern Utah. Since our acquisition, we have drilled nearly 700 wells. At year-end 2007, the field had more than 1,100 producing oil wells and gross daily production was nearly 14,000 BOPD. The field has thousands of remaining infill drilling opportunities. As in past years, we plan to drill approximately 200 wells in the field in 2008. Our activity levels in the field are dictated, in large part, by refining demand in the region and our ability to obtain drilling permits in a timely manner. Recent increased demand for Monument Butte crude oil is encouraging, and we expect to have sufficient drilling permits to allow us to run a four or five rig drilling program throughout 2008.

 

Green River Basin.  More than half of the proved reserves associated with the 2007 Rockies acquisition are located in the Pinedale field in Sublette County, Wyoming. We acquired interests in 8,000 gross acres (4,000 net acres) in the southeastern portion of the anticline. We see the potential to drill 100 additional locations as field spacing is decreased to 20 acres and eventually 10 acres. In 2007, we reached an agreement to assume operatorship of our activities in Pinedale. Approximately 13% of the reserves in our 2007 Rocky Mountain acquisition were located in the Jonah field, where we have identified more than 40 development locations on 10- and 5-acre well spacing.

 

Williston Basin.  Approximately 20% of the reserves associated with our 2007 Rockies acquisition were located in the Williston Basin. We have an interest in approximately 150,000 net acres. Current net production is more than 3,200 BOPD and has benefited from a recent well re-fracture program and new drilling in the Elm Coulee field, a mature Bakken play. Other targeted formations include the Madison, Red River and Duperow.

 

We remain active in conventional plays in onshore Texas, the Gulf of Mexico and offshore Malaysia and China.

 

Onshore Texas.  We are active in several plays in South Texas, in the Val Verde Basin of West Texas and in plays in East Texas. In South Texas, we have been very active under a joint venture agreement with ExxonMobil that is focused on the Frio play. This joint venture allows us to access new properties and to apply our knowledge in this area. Over the last three years, we have drilled 23 successful wells and grown production from zero to 75 MMcfe/d gross as of year-end 2007. Our wells in South Texas have high initial production rates and steep declines, so continued drilling is required to grow production. In the Val Verde Basin, our efforts are focused on the Canyon, Strawn and Ellenberger formations. Since entering the basin in

2002, we have grown production from approximately 20 MMcfe/d to approximately 70 MMcfe/d in early 2008. We have an interest in 130,000 gross acres. We believe that we have an opportunity for future growth in this area but growth will largely depend on our ability to have exploration success.

 

Gulf of Mexico.  Today, our efforts in the Gulf of Mexico are primarily focused on the deepwater. Our deepwater programs provide us with significant reserve exposure and represent a substantial component of our ongoing exploration efforts. We have two field developments underway and plans to drill four or five deepwater exploratory wells per year for the next several years from an inventory of leads and prospects we acquired in recent lease sales. Although we sold our shallow water Gulf of Mexico assets in 2007, we continue to make selective investments there to take advantage of the regional expertise of our employees and our significant 3-D seismic data base.

 

International.  We are active offshore Malaysia and China. We expect that more than 75% of our 2008 international budget will be spent in Malaysia, where we have several oil fields under development. Our activities in Malaysia began in 2004, and we continue to seek new opportunities. In China, we are producing 1,200 BOPD net from Bohai Bay. We also have three offshore exploration concessions — we began drilling on two of these concessions in late 2007.

Strategy

 

The elements of our growth strategy have remained substantially unchanged since our founding and consist of:

 

 

Drilling Program.  The components of our drilling program reflect the significant changes in our asset base over the last few years. To manage the risks associated with our strategy to grow reserves through the drill bit, a substantial majority of the wells we plan to drill in 2008 are lower risk with low to moderate reserve potential. We have lower-risk drilling opportunities in the Mid-Continent, the Rockies and the shallow waters of Malaysia. These opportunities are complemented with higher risk higher reserve potential plays in areas like the deepwater Gulf of Mexico and Malaysia, as well as deeper exploration plays in South Texas.

 

Acquisitions.  Acquisitions have consistently been a part of our strategy, particularly when entering new geographic regions. Since 2000, we have completed four significant acquisitions that led to the establishment of focus areas onshore U.S. We actively pursue the acquisition of proved oil and gas properties in select geographic areas. The potential to add reserves through the drill bit is a critical consideration in our acquisition screening process.

 

Geographic Focus.  We believe that our long-term success requires extensive knowledge of the geologic and operating conditions in the areas where we operate. Because of this belief, we focus our efforts on a limited number of geographic areas where we can use our core competencies and have a significant influence on operations. Geographic focus also allows more efficient use of capital and personnel.

 

Control of Operations and Costs.  In general, we prefer to operate our properties. By controlling operations, we can better manage production performance, control operating expenses and capital expenditures, consider the application of technologies and influence timing. At year-end 2007, we operated about 75% of our net total production.

 

Equity Ownership and Incentive Compensation.  We want our employees to act like owners, so we reward and encourage them through equity ownership and performance-based compensation. A significant portion of our employees’ compensation is contingent on our profitability. As of February 25, 2008, our employees owned or had options to acquire 7% of our outstanding common stock on a diluted basis.

Our Properties and Plans for 2008

 

Our capital budget for 2008 is approximately $1.6 billion, excluding $113 million of capitalized interest and overhead. We do not budget for potential acquisitions. Approximately 40% of the budget is allocated to the Mid-Continent, 20% to the Rocky Mountains, 15% to onshore Texas, 15% to the Gulf of Mexico and 10% to international projects. Our most significant investment projects are detailed below.

 

Mid-Continent.  Our activities in the Mid-Continent are focused primarily in the Anadarko and Arkoma Basins. As of December 31, 2007, we owned an interest in more than 750,000 gross acres and about 2,600 gross producing wells. This region is characterized by longer-lived natural gas production. Although our wells in this region are all fracture stimulated and have high initial production declines, our activity levels are leading to production growth. For 2008, we plan to invest about $620 million in the Mid-Continent. In total, we expect to drill or participate in approximately 200 wells in this focus area in 2008. We have two major activity areas in the region — the Woodford Shale in the Arkoma Basin and the Mountain Front Wash play in the Anadarko Basin.

 

The Woodford Shale play is our most active focus area — we plan to invest about $460 million in the play in 2008. We expect to operate 10–12 drilling rigs throughout the year, allowing us to drill about 100 operated horizontal wells. More than half of the wells will have lateral completions in excess of 3,000 feet. Longer laterals help improve our per unit finding and development costs. Nearly half of the planned wells will be drilled from common surface locations or pads, decreasing the footprint of our operations on the environment and providing further cost efficiencies. Our average working interest in the play is approximately 58%. In addition, we also will participate in the drilling of 50–60 wells operated by others.

 

We are planning to operate a 3–5 rig drilling program throughout 2008 in our Mountain Front Wash play. We expect to drill 60–70 wells and invest up to $120 million in the play.

 

Rocky Mountains.  As of December 31, 2007, we owned an interest in about 1.2 million gross acres, approximately 1,800 gross producing wells and 445 water injection wells. Our assets in the Rockies are nearly 70% oil and have long-lived production. In 2007, we acquired the Rocky Mountain assets of Stone Energy for $578 million, adding 200 Bcfe of proved reserves and exposure to new basins.

 

Our largest asset in the Rocky Mountains is the Monument Butte oil field. The field accounts for nearly 20% of year-end 2007 total proved reserves and encompasses more than 100,000 acres. Our working interest in the field averages 86%, and we operate the field and control the timing and pace of our operations. We have thousands of remaining infill drilling locations. Our production growth is influenced by the demand for our black wax crude from refiners in the Salt Lake City, Utah, area and our ability to obtain drilling permits in a timely manner. Substantially all of our Monument Butte production at year-end 2007 was being sold under firm contracts. Production from Monument Butte has benefited from increased demand for its black wax crude oil. We are working to secure additional long-term agreements with refiners. Please see the discussion under “Production growth at Monument Butte may be limited by the demand for our crude oil production” in Item 1A of this report.

 

We plan to drill 200 wells at Monument Butte in 2008. Our plans include the ongoing development of the field on 40-acre spacing, the conversion of existing producing wells to waterflood injector wells and an increasing number of 20-acre spaced infill wells. Over the last two years, we have drilled more than 50 wells on 20-acre spacing. Results indicate the potential to develop a large portion of the field on 20-acre spacing. A drilling rig is dedicated to this program in 2008.

 

In 2006, we signed an alliance with the Northern Ute Tribe, allowing us to drill wells on 47,000 gross acres located north and adjacent to Monument Butte. As of mid-February 2008, we had drilled 16 successful wells on this acreage and production has been consistent with wells in the main portion of the field. We will have a rig dedicated to drilling wells on this acreage throughout most of 2008.

 

There also is the potential for significant gas resources beneath the shallow producing oil sands at Monument Butte. Recent industry wells, as well as a few wells on our acreage that we have participated in, provide encouragement that the Wasatch, Mesa Verde, Blackhawk and Mancos Shale formations can be

exploited economically. We have signed an agreement with a third party that allows for promoted exploratory drilling and progressive earning in approximately 71,000 net acres in which we will retain a majority interest. Drilling under this agreement is expected to commence in the second quarter of 2008. Approximately 10,000 net acres in the immediate vicinity of our recent deep gas tests were excluded from the agreement and we plan to drill several wells on this acreage in 2008.

 

In the Green River Basin, we are active in the Pinedale and Jonah fields. We plan to drill 10 wells at Pinedale in 2008. Through an agreement reached in 2007, we assumed operatorship of the drilling program and increased our working interest to 85%. In the Jonah field, we are planning to drill five wells in 2008.

 

For 2008, we plan to drill at least 10 wells and invest approximately $50 million in the Williston Basin, including seismic purchases. Prospective targets in this region include the Madison, Red River and Duperow formations.

 

Onshore Texas.  As of December 31, 2007, we owned an interest in approximately 350,000 gross acres and about 650 gross producing wells onshore Texas.

 

We are active in most of the major producing trends in South Texas, including the Frio, Wilcox and Lobo plays. Our largest investment in South Texas in 2008 will be the Frio Trend. We have an interest in more than 60,000 acres in this trend, which is located primarily in Kenedy, Hidalgo, Brooks and Zapata Counties. In East Texas, we have an interest in 30,000 net acres, of which 11,000 net acres are associated with a joint venture with a private company.

 

To date, we have been very successful in a joint venture in Kenedy County with ExxonMobil adjacent to our existing Sarita field. Since the formation of the joint venture in 2005, we have drilled 23 successful wells and have a similar inventory of drilling locations. The area of activity today encompasses about 2,700 gross acres. The prospective horizons are numerous and gas is prevalent from 10,000 feet to as deep as 20,000 feet. Production at year-end 2007 was approximately 75 MMcfe/d gross. Our interest in the joint venture is approximately 50%.

 

In 2007, we formed a 40,000-acre joint venture with a private company that covers lands south and east of our existing ExxonMobil joint venture and also targets Frio horizons. Drilling is planned to begin in early 2008.

 

In the Val Verde Basin, we have an interest in nearly 130,000 gross acres located primarily in Val Verde, Terrell and Edwards Counties. At year-end 2007, our gross production from the area was approximately 70 MMcfe/d. Our working interests range from 50-100%. We plan to drill 10–12 wells in the basin in 2008.

 

Gulf of Mexico.  Our activities in the Gulf of Mexico are primarily focused on deepwater. At year-end 2007, our net daily production from the deepwater was nearly 40 MMcfe/d from four fields. As of December 31, 2007, we owned interests in 61 leases in deepwater (approximately 300,000 gross acres). We also own interests in 26 conventional shallow water lease blocks and a 10–25% interest in 85 shallow water lease blocks related to the ultra deep “Treasure Project” concept.

 

In the deepwater Gulf of Mexico, we have been active in recent lease sales and expect to continue this effort in 2008. We now have an inventory of prospects that will allow us to drill four or five exploratory wells per year over the next several years. We have two field developments underway in deepwater that will grow our production in the second half of 2008 and early 2009.

 

Our exploration efforts in deepwater can be classified into two distinct categories — prospects near existing infrastructure and those requiring stand-alone developments. The prospects located near infrastructure are generally smaller and lower risk than those requiring a stand-alone development. We prefer to operate prospects near existing infrastructure with interests ranging from 50–70%. Stand-alone developments are generally in deeper water (greater than 5,500 feet) and typically have long lead times. We often manage our exposure to these higher risk prospects by taking a smaller working interest or selling down our interest on a promoted basis.

International.  Our activities are focused primarily offshore Malaysia and China. We plan to invest $155 million in international activities in 2008, of which approximately 60% is dedicated to the ongoing development of oil fields offshore Malaysia.

 

Our shallow water concessions in Malaysia include a 50% non-operated interest in PM 318 and a 60% operated interest in PM 323. On PM 318, our Abu field commenced production in 2007 and production at year-end 2007 was approximately 14,000 BOPD gross. Our Puteri field is expected to commence production in the second quarter of 2008 and is expected to produce 6,000–8,000 BOPD gross. We have additional fields that will be developed and produced through existing infrastructure on this 414,000 acre concession. On PM 323, we are developing the East Belumut and Chermingat fields. First production is expected in mid-2008. These fields are expected to produce about 15,000 BOPD gross. We have additional exploration prospects on this 320,000 acre concession.

 

On deepwater Block 2C offshore Sarawak, which covers 1.1 million acres, we plan to drill our second commitment well in the second half of 2008. We will operate the exploratory well with a 40% interest.

 

In China, we are producing approximately 1,200 BOPD net from Bohai Bay. We also signed agreements with respect to three new blocks in the South China Sea that cover approximately 3.5 million gross acres. At year-end 2007, we were in the process of drilling two consecutive exploration wells on these concessions.

 

For revenues from our domestic and international operations, see Note 15, “Segment Information,” to our consolidated financial statements appearing later in this report.

 

Please see the discussion under the caption “Forward-Looking Information” in Item 7 of this report.

Marketing

 

Substantially all of our natural gas and oil production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market sensitive prices. For a list of purchasers of our oil and gas production that accounted for 10% or more of our consolidated revenue for the three preceding calendar years, please see Note 1, “Organization and Summary of Significant Accounting Policies — Major Customers,” to our consolidated financial statements. We believe that the loss of any of these purchasers would not have a material adverse effect on us because alternative purchasers are readily available.

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 in deepwater in the Gulf of Mexico. For a further discussion, please see the information regarding competition set forth in Item 1A of this report.

Employees

 

As of February 15, 2008, we had 927 employees. All but 76 of our employees were located in the U.S. None of our employees are covered by a collective bargaining agreement. We believe that relationships with our employees are satisfactory.

Regulation

 

For a discussion of the significant governmental regulations to which our business is subject, please see the information set forth under the caption “Regulation” in Item 7 of this report.

 

An investment in our securities involves risks. You should carefully consider, in addition to the other information contained in this report, the risks described below.

 

Oil and gas 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 depend substantially on prevailing prices for oil and gas. These prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount that we can borrow under our credit facility could be limited by changing expectations of future prices. In addition, lower prices may reduce the amount of oil and gas that we can economically produce.

 

Among the factors that can cause fluctuations are:

 

 

To maintain and grow our production and cash flow, we must continue to develop existing reserves and locate or acquire new oil and gas reserves.  We accomplish this through successful drilling programs and the acquisition of properties. However, we may be unable to find, develop or acquire additional reserves or production at an acceptable cost. In addition, these activities require substantial capital expenditures. Our 2008 capital budget exceeds currently expected cash flow from operations and cash and short-term investments on hand at year end 2007 by approximately $260 million. In the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We anticipate that the shortfall will be made up with cash and short-term investments on hand and borrowings under our credit arrangements. Lower oil and gas prices or unexpected operating constraints or production difficulties will decrease cash flow from operations and could limit our ability to borrow under our credit arrangements. We also currently expect that our 2009 capital budget will exceed expected cash flow from operations. Our ability to fund attractive acquisition opportunities and future capital programs may be dependent on our ability to access capital markets. Further or continued volatility in the credit markets could adversely impact our ability to obtain financing on acceptable terms. Because all of our credit arrangements provide for variable interest rates, higher interest rates would also reduce cash flow. For a detailed discussion of our credit arrangements and liquidity, please see “Liquidity and Capital Resources” in Item 7 of this report.

 

Our use of oil and gas price hedging contracts involves credit risk and may limit future revenues from price increases.  We generally hedge a substantial, but varying, portion of our anticipated future oil and natural gas production for the next 12-24 months as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices for natural gas and those of our physical pricing points. In the case of acquisitions, we may hedge acquired production for a longer period. We use hedging to reduce price volatility, help ensure that we have adequate cash flow to fund our capital programs and manage price risks and returns on some of our acquisitions and drilling programs. While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.

 

Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves most likely will vary from our estimates.  Estimating accumulations of oil and gas is complex. The process relies

on interpretations of available geologic, geophysic, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires a number of economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

 

 

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

 

Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses most likely will vary from our estimates. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activities and prevailing oil and gas prices. 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 oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs in effect at year-end. Actual future prices and costs may be materially higher or lower than the prices and costs we used. In addition, actual production rates for future periods may vary significantly from the rates assumed in the calculation.

 

If oil and gas prices decrease, we may be required to take writedowns.  We may be required to writedown the net capitalized costs of our oil and gas properties when oil and gas prices decrease or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs or deterioration in our exploitation results.

 

We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost accounting method. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net cash flows from proved reserves, using period-end oil and gas prices and a 10% discount factor, plus the lower of cost or fair market value for unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. We review the net capitalized costs of our properties quarterly, based on prices in effect (excluding the effect of our hedging contracts that are not designated for hedge accounting) as of the end of each quarter or as of the time of reporting our results. The net capitalized costs of oil and gas properties is computed on a country-by-country basis. Therefore, while our properties in one country may be subject to a writedown, our properties in other countries could be unaffected. Once recorded, a writedown of oil and gas properties is not reversible at a later date even if oil and gas prices increase.

 

Production growth at Monument Butte may be limited by the demand for our crude oil production.  The crude oil produced in the Uinta Basin is known as “black wax” because it has a higher paraffin content than crude oil found in most other major North American basins. Due to its waxy composition, the oil is transported by truck to refiners in the Salt Lake City area. These refiners have limited capacity to refine this type of crude. We currently have agreements in place with four area refiners that secure base load capacity of approximately 14,000 BOPD through 2008 and 12,500 BOPD through 2009. We are working with the refiners to secure additional capacity to allow for continued production growth. Without additional refining capacity, our ability to increase production from the field may be limited.

Competition for experienced technical personnel may negatively impact our operations or financial 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 experienced explorationists, engineers and other professionals. Competition for these professionals is extremely intense. We are likely to continue to experience increased costs to attract and retain these professionals.

 

Competition for available oil and gas properties is extremely intense.  Our competitors include major oil and gas companies, independent oil and gas companies and financial buyers. Some of our competitors may have greater and more diverse resources than we do. Recently, higher commodity prices and stiff competition for acquisitions have significantly increased the cost of available properties.

 

We may be unable to obtain the drilling rigs or support services necessary for our offshore drilling and development programs in a timely manner or at acceptable rates.  In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for offshore drilling rigs, drilling vessels, dive boats, supply boats and experienced personnel. The market for oilfield services is currently very competitive. This may lead to difficulty and delays in consistently obtaining services and equipment from vendors, obtaining drilling rigs and other equipment at acceptable rates, and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or increased costs.

 

We may be subject to risks in connection with acquisitions.  The successful acquisition of producing properties requires an assessment of several factors, including:

 

 

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. Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.

 

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. In addition, we often are uncertain as to 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:

 

 

 

The oil and gas business involves many operating risks that can cause substantial losses; insurance may not protect us against all these risks.  These risks include:

 

 

If any of these events occur, we could incur substantial losses as a result of:

 

 

If we experience any of these problems, our ability to conduct operations could be adversely affected.

 

Offshore operations are subject to a variety of operating risks, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. Some of our offshore operations are dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Necessary infrastructures may be temporarily unavailable due to adverse weather conditions or may not be available to us in the future.

 

We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not insurable.

 

Exploration in deepwater may involve significant financial risks.  Much of the deepwater play lacks the physical and oilfield service infrastructure necessary for production. As a result, development of a deepwater discovery may be a lengthy process and require substantial capital investment. Because of their size, we may not serve as the operator of significant projects in which we invest. As a result, we may have limited ability to exercise influence over operations related to these projects or their associated costs. Our dependence on the operator and other working interest owners for these deepwater projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital. In addition, there is limited availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel.

 

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.  Exploration and development and the production and sale of oil and gas are subject to extensive federal, state,

local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

 

 

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 damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these 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. Moreover, these laws could change in ways that substantially increase our costs. 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.

 

We have risks associated with our foreign operations.  Ownership of property interests and production operations in areas outside the United States is subject to the various risks inherent in foreign operations. These risks may include:

 

 

Our international operations also may be adversely affected by the laws and policies of the United States affecting foreign trade, taxation and investment. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States.

 

Our certificate of incorporation, bylaws, stockholder rights plan and some of our arrangements with employees contain provisions that could discourage an acquisition or change of control of our company.  Our stockholder rights plan, together with certain provisions of our certificate of incorporation and bylaws, may make it more difficult to effect 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, our omnibus stock plans and our incentive compensation plan 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. These provisions could discourage or prevent a change of control or reduce the price our stockholders receive in an acquisition of our company.

 

 

None.

 

The information appearing in Item 1 of this Annual Report is incorporated herein by reference.

Concentration

 

At year end-2007, 96% of our proved reserves were located in the U.S. and 92% were located onshore. Our 10 largest fields or plays accounted for approximately 77% of our proved reserves at year-end 2007. The largest of those, the Woodford Shale play and the Monument Butte field accounted for about 43% of our proved reserves and around 36% of the net present value of our proved reserves at December 31, 2007.

Proved Reserves and Future Net Cash Flows

 

The following table shows our estimated net proved oil and gas reserves and the present value of estimated future after-tax net cash flows related to those reserves as of December 31, 2007.

 

 

 

 

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. Actual quantities of recoverable reserves and future cash flows from those reserves most likely will vary from the estimates set forth above. Reserve and cash flow estimates rely on interpretations of data and require many assumptions that may turn out to be inaccurate. For a discussion of these interpretations and assumptions, see “Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves most likely will vary from our estimates” under Item 1A of this report.

Drilling Activity

 

The following table sets forth our drilling activity for each year (other than drilling activity related to our discontinued operations in the United Kingdom) in the three-year period ended December 31, 2007.

 

 

 

 

We were in the process of drilling 61 gross (36.5 net) exploratory wells (includes 58 gross (35.2 net) exploitation wells) and eight gross (3.7 net) development wells in the United States and one gross (1.0 net) exploratory well in China at December 31, 2007.

Productive Wells

 

The following table sets forth the number of productive oil and gas wells in which we owned an interest as of December 31, 2007 and the location of, and other information with respect to, those wells.

 

 

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 customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.

Acreage Data

 

As of December 31, 2007, we owned interests in developed and undeveloped oil and gas acreage in the locations set forth in the table below. Domestic ownership interests generally take the form of “working interests” in oil and gas leases that have varying terms. International ownership interests generally arise from participation in production sharing contracts.

 

The table below summarizes by year and geographic area 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 acreage beyond the expiration date. We own fee mineral interests in 359,005 gross (101,925 net) undeveloped acres. These interests do not expire.

 

Title to Properties

 

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry in the case of undeveloped properties, often little investigation of record title is made at the time of acquisition. Investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

 

 

In December 2002, a lawsuit against our Mid-Continent subsidiary was filed in Beaver County, Oklahoma and was later certified as a class action royalty owner lawsuit. The complaint alleged that we improperly reduced royalty payments for certain expenses and charges, and also claimed breach of contract and breach of fiduciary duties, among other claims. In April 2007, we entered into a settlement agreement that has since received court approval.

 

We also have been named as a defendant in a number of other lawsuits that arose in the ordinary course of our business. While the outcome of these lawsuits 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.

 

There were no matters submitted to a vote of our security holders during the fourth quarter of 2007.

 

 

The following table sets forth the names and ages (as of February 29, 2008) of and positions held by our executive officers. Our executive officers serve at the discretion of our Board of Directors.

 

 

The executive officers have held the positions indicated above for the past five years, except as follows:

 

David A. Trice reassumed the role of President in October 2007. He was appointed Chairman in September 2004.

 

Lee K. Boothby was promoted to his present position in October 2007. He managed our Mid-Continent operations from February 2002 to October 2007, and was promoted from General Manager to Vice President in November 2004.

 

Terry W. Rathert was promoted from Vice President to Senior Vice President in November 2004.

 

Michael D. Van Horn joined our company as Senior Vice President in November 2006. He served at EOG Resources, and its predecessor Enron Oil and Gas, from 1993 to November 2006. Most recently, he served as Vice President of International Exploration. Prior to that position, he was Director of Exploration.

 

Mona Leigh Bernhardt was promoted from Manager to Vice President in December 2005.

 

W. Mark Blumenshine was promoted from Manager to Vice President in December 2005.

 

Stephen C. Campbell was promoted from Manager to Vice President in December 2005.

 

George T. Dunn was named Vice President – Mid-Continent 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.

John H. Jasek was named Vice President – Gulf Coast in October 2007 and became the manager of our onshore Gulf Coast operations. He has managed our Gulf of Mexico operations since March 2005, 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.

 

James J. Metcalf was promoted from Manager to Vice President in December 2005.

 

Gary D. Packer was promoted from a Gulf of Mexico General Manager to Vice President – Rocky Mountains in November 2004.

 

Mark J. Spicer was promoted from Manager to Vice President in December 2005.

 

James T. Zernell was promoted from Manager to Vice President in December 2005.

 

John D. Marziotti was promoted to General Counsel in August 2007. From November 2003, when he joined our company, until August 2007 he held the position of Legal Counsel. Prior to joining us, he was a shareholder of the law firm of Strasburger & Price, LLP.

PART II

 

 

Our common stock is listed on the New York Stock Exchange 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.

 

 

On February 25, 2008, the last reported sales price of our common stock on the NYSE was $53.20 per share. As of that date, there were approximately 1,885 holders of record of our common stock.

 

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 65/8% Senior Subordinated Notes due 2014 and 2016 could restrict our ability to pay cash dividends.

 

The following table sets forth certain information with respect to repurchases of our common stock during the three months ended December 31, 2007.

 

 

 

The performance presentation shown 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:

 

 

Our peer group is comprised of Anadarko Petroleum Corporation, Apache Corporation, Bill Barrett Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, EOG Resources, Inc., Forest Oil Corporation, Murphy Oil Corporation, Noble Energy, Inc., Pioneer Natural Resources Company, Range Resources Corporation, St. Mary Land & Exploration Company, Stone Energy Corporation, Swift Energy Company and XTO Energy Inc.

 

 

 

SELECTED FIVE-YEAR FINANCIAL AND RESERVE DATA

 

The following table shows selected consolidated financial data derived from our consolidated financial statements and selected reserve data derived from our supplementary oil and gas disclosures set forth in Item 8 of this report. The data should be read in conjunction with Item 2, “Properties  — Proved Reserves and Future Net Cash Flows” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this report.