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.  þ

 

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 $8.5 billion as of June 30, 2008 (based on the last sale price of such stock as quoted on the New York Stock Exchange).

 

As of February 23, 2009, there were 132,794,710 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 7, 2009, which is incorporated by reference to the extent specified in 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. This report contains information that is forward-looking or relates to anticipated future events or results. See “Forward-Looking Information.”

 

 

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. We are also 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 them with, or furnish them to, the Securities and Exchange Commission. 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.

 

We are a Delaware corporation and were founded in 1989. For the first 10 years of our existence, we focused almost exclusively on the shallow waters of the Gulf of Mexico. In the late 1990s, our operations expanded to other regions. This broadened scope allowed us to gain access to properties and opportunities necessary for continued growth. 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 in both oil and gas basins; 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 2008, we had proved reserves of 2.95 Tcfe. Those reserves were 72% natural gas and 62% proved developed. As a result of our increasing investments in unconventional “resource” plays in the Mid-Continent and Rocky Mountains and the sale of our shallow water Gulf of Mexico assets in 2007, our reserve life index is now more than 12.5 years.

 

 

Both oil and gas prices declined rapidly in the second half of 2008. In addition, capital markets are constrained due to global financial and economic conditions. The confluence of these events led us to make some changes in our planned activities and spending levels for 2009. Our diversified portfolio of assets

provides us with flexibility in our capital allocation process. We have reduced our original spending plans for 2009 by nearly 30% and expect that our investment levels will match our total 2009 cash flows from operations. Our cash flow assumptions for 2009 assume a positive benefit from our hedging position. For a complete discussion of our hedging activities, a listing of open contracts as of December 31, 2008 and the estimated fair value of these contracts as of that date, see Note 5, “Commodity Derivative Instruments,” to our consolidated financial statements.

 

Our capital investment plan in 2009 preserves available liquidity, ensures our leverage ratios remain at what we consider to be acceptable levels and provides for the ongoing development of our largest assets. With the expectation that commodity prices could remain low throughout 2009, we reduced our investment levels in basins where oil and gas prices are typically weaker due to the distance from consuming markets and resulting price basis differentials. As an example, we have reduced our gas drilling plans in the Rocky Mountains and allocated more to the Mid-Continent where firm transportation agreements ensure higher realized prices. In our two largest development areas — the Woodford Shale and Monument Butte — substantially all of our acreage is “held by production,” which means that a reduction in our activity levels in those areas will not result in lost opportunities. We also have sold down our interest or taken partners who have agreed to pay a disproportionate share of costs in areas like the deepwater Gulf of Mexico to both reduce our risks and stretch our capital investments. In South Texas, we have significantly reduced our planned exploration expenditures due to project economics at lower commodity prices. In Malaysia, we also were able to defer some of our planned activities and investments into 2010.

 

Our 2009 capital budget is $1.45 billion, including approximately $130 million of estimated capitalized interest and overhead. We expect our 2009 production to grow 6-10% over 2008 levels. Our planned capital investments include funding projects that will lead to future growth. At our planned level of investments in 2009, we expect to have comparable production growth in 2010. We have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations.

 

Please see the discussion under “We have substantial capital requirements to fund our business plans, and the current poor conditions generally in the economy and in the financial markets could jeopardize our ability to execute our business plans” and the other disclosures in Item 1A of this report.

 

At year-end 2008 approximately 65% of our proved reserves were in “resource” plays. 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 have been enhanced by continued advancements in drilling and completion technologies. These advancements make resource plays resilient to lower commodity prices. Today, we have two large resource plays — the Woodford Shale in the Arkoma Basin of southeast Oklahoma and Monument Butte in northeast Utah.

 

Woodford Shale.  Our largest single investment area over the last three years has been the Woodford Shale. Our activities began in this area in 2003. At year-end 2008, we owned an interest in approximately 165,000 net acres. Our average working interest is approximately 60%. Since 2003, we have drilled more than 100 vertical wells and 245 horizontal wells. The Woodford is a shale formation that varies in thickness from 100 — 200 feet throughout our acreage. Our 2008 production was 65% higher than in 2007 and at year-end 2008 was approximately 250 MMcfe/d (gross). Full development of the play will require several thousand wells. Our development program consists of drilling wells on 40 acre spacing and we are drilling an increasing number of horizontal wells with longer lateral completions. A long lateral completion is defined as a horizontal section in the Woodford up to 10,000 feet in length. About 80% of our planned wells in 2009 will be drilled from common surface locations or pads, reducing both costs and our impact on the environment.

 

Monument Butte.  Our largest asset in the Rocky Mountains is the Monument Butte oil field, located in the Uinta Basin of Utah. The field accounts for approximately 20% of our year-end 2008 proved reserves and encompasses about 184,000 gross acres, including nearly 45,500 net acres added through two ventures with Ute Energy LLC. Our working interest in the field averages 86%. We operate the field and control the timing

and pace of our operations. Since we purchased the Monument Butte field in 2004, we have drilled 916 wells and have thousands of remaining infill drilling locations. At year-end 2008, the field had 1,273 productive oil wells and gross daily production of more than 16,500 BOPD.

 

Our activity levels and production growth in the field are set in accordance with 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. About half of our Monument Butte production at year-end 2008 was being sold under firm contracts. Area refiners have added new refining capacity over the past months and we expect that demand for our black wax crude oil will increase. However, in the current economic and capital market environments, there is an increased risk that purchasers of our black wax crude production may fail to satisfy their obligations to us under those contracts. We are working to secure additional long-term agreements with refiners. Please see the discussion under “There is limited refining capacity for our black wax crude oil, and our ability to sell our current production or to increase our production at Monument Butte may be limited by the demand for our crude oil production” in Item 1A of this report.

 

Granite Wash.  In addition to the Woodford Shale, we are also active in the Granite Wash play (also known as Mountain Front Wash), located in the Anadarko Basin. We drilled our first horizontal well in the Granite Wash in late 2008 and plan several more. We believe that we have 90-100 remaining horizontal drilling locations in the Granite Wash. Our production in the play reached 130 MMcfe/d (gross) in early 2009, a record level. Our largest producing field in the play is Stiles Ranch, where our working interest is predominately 100%.

 

Williston Basin.  We have a growing position in the Williston Basin and at year-end 2008 had an interest in approximately 470,000 net acres. Our drilling successes in 2008 increased our net production to approximately 2,500 BOPD in mid-February 2009. Targeted geologic formations in the basin include the Three Forks/Sanish, Bakken, Madison, Red River and Duperow.

 

Green River Basin.  We own interests in 8,000 gross acres (4,000 net acres) in the Pinedale Field, located in Sublette County, Wyoming. We see the potential to drill approximately 120 additional locations as field spacing is decreased to 20 acres and eventually to 10 acres. We operate our activities in Pinedale. We also have an interest in the Jonah field, located in Sublette County, Wyoming, where we have identified about 35 development locations on 10- and 5-acre well spacing.

 

We also have operations in conventional plays in onshore Texas, the Gulf of Mexico and offshore Malaysia and China.

 

Onshore Texas.  We are active in South Texas, the Val Verde Basin of West Texas and in East Texas. We have a presence in most of the major producing trends in onshore Texas and our gross production was approximately 225 MMcfe/d at year-end 2008. Our drilling program over the last several years has focused on the Wilcox, Vicksburg and Frio plays in South Texas. In these trends, we have an interest in more than 60,000 gross acres primarily in Kenedy, Hidalgo, Brooks and Zapata Counties, including two joint ventures with ExxonMobil. In East Texas, we have an interest in 36,000 net acres.

 

We have interests in nearly 130,000 gross acres in the Val Verde Basin where prospective drilling targets include the Canyon, Strawn and Ellenberger formations. Our production from the area was approximately 50 MMcfe/d (gross) at year-end 2008 and our working interests range from 50% to 100%.

 

Gulf of Mexico.  We remain active in the Gulf of Mexico and have growing operations in the deepwater. At year-end 2008, our daily production capacity from the Gulf of Mexico was approximately 50 MMcfe/d (net), which includes about 25 MMcfe/d (net) shut-in due to hurricane repairs. As of December 31, 2008, we owned interests in 76 deepwater leases (approximately 438,000 gross acres) and 26 leases on the shelf.

 

We have five deepwater field developments underway that are expected to provide future production growth. We have an inventory of prospects acquired primarily through federal lease sales over the last two years. Our deepwater program provides us with significant reserve exposure and represents a substantial component of our

ongoing exploration efforts. Our deepwater exploration efforts can be classified into two distinct categories — prospects near existing infrastructure and those requiring stand-alone developments. The prospects located near existing 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 30 — 70%. Stand-alone developments are generally in water depths greater than 5,500 feet and have longer lead times for development. We often manage our exposure to these higher risk prospects by taking a smaller working interest or selling down our interest to others who have agreed to pay a disproportionate share of drilling costs.

 

We make selective investments in the shallow water Gulf of Mexico to take advantage of our regional expertise and 3-D seismic data base. We have made four discoveries since late 2007 that are expected to add to our production volumes in 2009 and 2010.

 

International.  We are active offshore Malaysia and China. Our international production at year-end 2008 was 17,500 BOPD (net), an increase of 175% over 2007. The increase was related primarily to new field developments in Malaysia that commenced production in 2008.

 

Our activities in Malaysia began in 2004 and in early 2009 we had production of approximately 43,000 BOPD (gross) from seven shallow water oil developments. Our Malaysian concessions include a 50% non-operated interest in PM 318 (435,000 gross acres) and a 60% operated interest in PM 323 (353,000 gross acres). On PM 318, our Abu field commenced production in 2007 and production at year-end 2008 was approximately 14,000 BOPD (gross). Our Puteri field commenced production in the third quarter of 2008 and has the capacity to produce 6,000 — 8,000 BOPD (gross). On PM 323, first production commenced from our East Belumut and Chermingat fields in the third quarter of 2008 and had gross production of about 15,000 BOPD at year-end 2008. In 2008, we signed two new production sharing contracts on shallow water Block SK 310 (1.1 million gross acres) and PM 329 (96,000 gross acres).

 

We also have interests in deepwater Block 2C offshore Sarawak (1.1 million acres). As of mid-February 2009, we were in the process of drilling a high-risk high-potential deepwater prospect on Block 2C. This is our second of two required commitment wells on this block. We operate the exploratory well with a 40% interest.

 

In Bohai Bay, China, we have production of 1,800 BOPD (net) through our outside operated interests. We also have three offshore exploration concessions in the South China Sea that cover approximately 3.5 million gross acres. We made an oil discovery on this acreage in 2008 that will require additional drilling to determine its commerciality.

 

For revenues from and income taxes related to our domestic and international operations, see Note 15, “Segment Information,” and Note 10, “Income Taxes,” to our consolidated financial statements appearing later in this report.

 

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. An increasing portion of our drilling budget is being allocated to our longer-lived resource plays. Due to our capital allocation plans in 2009, the majority of our wells will be lower risk development wells in our Mid-Continent and Rocky Mountain regions.

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 will continue to screen for value-adding acquisitions.

 

Geographic Focus.  We believe that our long-term success 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 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 2008, we operated about 80% of our total net 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 tied to profitability. As of February 23, 2009, our employees owned or had options to acquire at least 5% of our outstanding common stock on a diluted basis.

 

Our largest investment regions in 2009 will be the Mid-Continent and the Rocky Mountains. Approximately 43% of the budget is allocated to the Mid-Continent, 17% to the Rocky Mountains, 18% to the Gulf of Mexico, 14% to onshore Texas and 8% 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, 2008, we owned a working interest in more than 750,000 gross acres and approximately 2,000 gross producing wells. This region is characterized by longer-lived natural gas production. For 2009, we plan to invest about $610 million in the Mid-Continent to operate the drilling of about 100 wells.

 

We plan to invest approximately $450 million of the total Mid-Continent capital budget in the Woodford Shale in 2009. We expect to drill about 80 operated horizontal wells by running 11 rigs throughout the year. Throughout 2008, we increased the length of our lateral completions, adding improved gas recoveries, higher production rates and better overall economics. Although we will run one less rig in 2009 than in 2008, we expect to drill and complete an additional 100,000 feet of Woodford section. Simply stated, we are drilling our wells faster and more efficiently. We expect that the average length of our lateral completions in 2009 will exceed 5,000 feet and that 75% of our planned wells will be drilled from common surface locations or pads. In addition, we also will participate in the drilling of 60 — 70 wells operated by others in this area.

 

We plan to operate one or two drilling rigs in our Granite Wash play. We recently drilled our first horizontal well in this play and are encouraged by the initial results. We are planning to drill about 10 additional horizontal wells in the field in 2009 and invest $60 — $70 million.

 

Rocky Mountains.  As of December 31, 2008, we owned an interest in about 1.2 million gross acres and approximately 1,950 gross producing 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.

 

We plan to run a three-rig drilling program in 2009 and expect to drill about 150 wells at Monument Butte. This is a 100 well reduction from our 2008 drilling and reflects a reduced capital investment in this long-lived oil field. Because this field is held-by-production, our reduced activity levels will not result in lost opportunities. Our program will focus on continued development of the field on 40 and 20 acre locations. We have an estimated 1,000 locations remaining to drill the field down to 40-acre spacing. We have drilled 128 wells on 20-acre spacing and results indicate that a large portion of the field will be developed on 20-acre spacing. We have an estimated additional 1,000 — 2,500 locations remaining to drill the field down to 20-acre spacing. We will continue to invest on the 45,500 net acres north and adjacent to the Monument Butte field that we have interests in with Ute Energy LLC. As of mid-February 2009, we had drilled more than 45 wells on this acreage and results are consistent with those from our main field.

There is a significant gas resource beneath the shallow producing oil zones at Monument Butte. In 2008, we participated in the drilling of six deep tests to evaluate these gas-bearing formations — the Wasatch, Mesa Verde, Blackhawk, Mancos and Dakota. We were encouraged by our results and believe that the deep gas play will be commercial at higher natural gas prices. We have deferred additional drilling expenditures in the play in 2009 and will study our recently collected data. Our collection of data in 2008 was aided by a deep gas agreement that we signed with Red Technology Alliance. The agreement allowed for promoted exploratory drilling and progressive earning in approximately 71,000 net acres in which we retain a majority interest. Three of the wells we drilled in 2008 were under this agreement. Red Technology Alliance plans to drill several additional wells in this area in 2009 to further define this resource. Approximately 10,000 net acres in the immediate vicinity of our recent deep gas tests were excluded from the agreement with Red Technology Alliance. We drilled three successful operated wells in this area in 2008.

 

We also have an active program in the Williston Basin. We will maintain a one-rig program in 2009 focused on drilling exploration wells to assess acreage for future development, as well as to drill wells to hold recently acquired acreage through production. To date, we have drilled nine successful wells with production from the Bakken and Three Forks/Sanish formations. During 2009, we expect to drill about 10-12 additional wells and invest about $45 million.

 

Gulf of Mexico.  Our activities in the Gulf of Mexico are primarily focused on deepwater. Through bidding successes at recent lease sales, we established a large inventory of prospects in the deepwater Gulf of Mexico, which have a 10-year term. As of mid-February 2009, we were in the process of drilling the second of two planned exploration wells. We have five deepwater field developments underway that are expected to grow our production in 2009 through 2012.

 

Onshore Texas.  As of December 31, 2008, we owned an interest in approximately 400,000 gross acres and about 1,000 gross producing wells onshore Texas. We expect to drill 25 — 30 wells in this region in 2009.

 

International.  Our international activities are focused offshore Malaysia and China. We plan to invest $95 million in 2009, which includes one deepwater exploratory well in Malaysia and continued development drilling in our shallow water oil fields.

 

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 with the exception of purchasers of our Monument Butte field oil production. Due to the higher paraffin content of this production, there is limited refining capacity for it. Please see the discussion under “There is limited refining capacity for our black wax crude oil, and our ability to sell our current production or to increase our production at Monument Butte may be limited by the demand for our crude oil production” in Item 1A of this report.

 

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

 

As of February 23, 2009, we had 1,054 employees. All but 95 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.

 

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.

 

This report contains information that is forward-looking or relates to anticipated future events or results, such as planned capital expenditures, future drilling plans and programs, expected production rates, the availability and source of capital resources to fund capital expenditures, estimates of proved reserves and the estimated present value of such reserves, our financing plans and our business strategy and other plans and objectives for future operations. Although we believe that these expectations 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:

 

 

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 “Item 1. Business,” “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. We do not intend to update these statements unless securities laws require us to do so.

 

 

There are many factors that may affect Newfield’s business and results of operations. 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. Lower prices may reduce the amount of oil and gas that we can economically produce. 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 because the amount that we may borrow under our credit facility is determined by our lenders annually each May (and may be redetermined at the option of our

lenders in the case of certain acquisitions or divestitures) using a process that takes into account the value of our estimated reserves and hedge position and the lenders’ commodity price assumptions.

 

Among the factors that can cause fluctuations in oil and gas prices are:

 

 

We have substantial capital requirements to fund our business plans, and the current poor conditions generally in the economy and in the financial markets could jeopardize our ability to execute our business plans.  Although we have reduced our 2009 capital budget to a level that we believe corresponds with our anticipated 2009 cash flows, since the timing of capital expenditures and the receipt of cash flows do not necessarily match, we anticipate borrowing and repaying funds under our credit arrangements throughout the year. We may have to further reduce capital expenditures and our ability to execute our business plans could be diminished if (1) one or more of the lenders under our existing credit arrangements fail to honor its contractual obligation to lend to us, (2) the amount that we are allowed to borrow under our existing credit facility is reduced as a result of lower oil and gas prices, declines in reserves, lending requirements or for other reasons or (3) our customers or working interest owners default on their obligations to us.

 

Global credit markets have been, and continue to be, distressed. In this environment, the cost of raising money in the financial markets has increased while the availability of funds from those markets has diminished. In the current environment, many lenders have increased rates, imposed tighter lending standards, refused to refinance existing debt at maturity or on similar terms to existing debt and have reduced or ceased to provide new funding.

 

In addition, to the extent that purchasers of our production or our working interest owners have difficulty financing their business activities, there could be an increased risk that purchasers of our production may default in their contractual obligations to us or that working interest owners may be unable or unwilling to pay their share of costs as they become due. Although we perform credit analyses on our customers, the general downturn in the economy and tightening of the financial markets could increase the risk that our customers and working interest owners fail to perform.

 

Our use of oil and gas price hedging contracts may limit future revenues from price increases and involves the risk that our counterparties may be unable to satisfy their obligations to us.  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 the case of significant acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive drilling programs. Although 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 counterparties, which generally are financial institutions, may be unable to satisfy their obligations to us. Although we have entered into hedging 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 hedging 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 the current economic environment and tight financial markets, the risk of a counterparty default is heightened and it is possible that fewer counterparties will participate in future 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.

 

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. Although we have reduced our 2009 capital budget to a level that we believe corresponds with our anticipated 2009 cash flows, we anticipate borrowing and repaying funds under our credit arrangements throughout the year to the extent that the timing of capital expenditures and the receipt of cash flows from operations do not match. We anticipate that any cash flow shortfall will be made up with cash 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. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. 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 at all or 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 and Note 9, “Debt,” to our consolidated financial statements in Item 8 of this report.

 

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.

 

There is limited refining capacity for our black wax crude oil, and our ability to sell our current production or to increase our production at Monument Butte may be limited by the demand for our crude oil production.  Most of the crude oil we produce in the Uinta Basin is known as “black wax” because it has

higher paraffin content than crude oil found in most other major North American basins. Due to its wax content, it must remain heated during shipping, so the oil is transported by truck to refiners in the Salt Lake City area. We currently have agreements in place with two area refiners that secure base load sales of approximately 5,000 BOPD through the end of 2009. In the current economic environment and tight financial markets, there is an increased risk that they may fail to satisfy their obligations to us under those contracts. During the fourth quarter of 2008, the largest purchaser of our black wax crude oil failed to pay for certain deliveries of crude oil and filed for bankruptcy protection. Although we continue to sell our black wax crude oil to that purchaser on a short-term basis that provides for more timely cash payments, we cannot guarantee that we will be able to continue to sell to this purchaser or that similar substitute arrangements could be made for sales of our black wax crude oil with other purchasers if desired. We continue to work with refiners to expand the market for our existing black wax crude oil production and to secure additional capacity to allow for production growth. However, without additional refining capacity, our ability to increase production from the field may be limited.

 

Lower oil and gas prices and other factors resulted in a ceiling test writedown and may in the future result in additional ceiling test writedowns or other impairments.  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. This is called a “ceiling test writedown.” As of December 31, 2008, we recorded a $1.8 billion ($1.1 billion after-tax) ceiling test writedown. Although a ceiling test writedown does not impact cash flow from operations, it does reduce our stockholders’ equity. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.

 

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 are 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. We also assess investments in unproved properties periodically to determine whether impairment has occurred.

 

The risk that we will be required to further write down 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. We may experience further ceiling test writedowns or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

 

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 of 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 and deepwater 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 have in the past, and may in the future, cause substantial damage to facilities and interrupt production. Some of our offshore operations, and most of our deepwater operations, are dependent upon the availability, proximity and capacity of pipelines, natural gas 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 may not be available to us in the future at all or on acceptable terms.

 

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 involves significant financial risks, and we may be unable to obtain the drilling rigs or support services necessary for our deepwater drilling and development programs in a timely manner or at acceptable rates.  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 drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel, and deepwater drilling rigs typically are subject to long-term contracts. This can lead to difficulty and delays in consistently obtaining

drilling rigs and other equipment and services at acceptable rates, which, in turn, may lead to projects being delayed or increased costs. This also makes it difficult to estimate the timing of our production.

 

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. Despite the recent decline in commodity prices and lower industry activity levels, competition for these professionals remains strong. We are likely to continue to experience increased costs to attract and retain these professionals.

 

There is competition for available oil and gas properties.  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. 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 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.

 

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.

 

Potential regulations regarding climate change could alter the way we conduct our business.  Governments around the world are beginning to address climate change matters. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows.

 

We have risks associated with our non-U.S. operations.  Ownership of property interests and production operations in areas outside the United States is subject to the various risks inherent in international 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 international 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.

 

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 bylaws contain provisions that 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. 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 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.

 

At year end 2008, 94% of our proved reserves were located in the U.S. and 89% were located onshore. Our 10 largest fields or plays accounted for approximately 79% of our proved reserves at year-end 2008. The largest of those, the Woodford Shale play and the Monument Butte field, accounted for about 48% of our proved reserves and around 33% of the net present value of our proved reserves at December 31, 2008.

 

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, 2008.

 

 

 

 

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.

 

The following table sets forth our drilling activity for each year (other than drilling activity related to our operations in the United Kingdom which were discontinued in 2007) in the three-year period ended December 31, 2008.

 

 

 

 

We were in the process of drilling 58 gross (34.1 net) exploratory wells (includes 57 gross (33.1 net) exploitation wells) and six gross (4.9 net) development wells in the United States at December 31, 2008. There were no wells being drilled internationally at December 31, 2008.

 

The following table sets forth the number of productive oil and gas wells in which we owned an interest as of December 31, 2008 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.

 

As of December 31, 2008, 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 363,402 gross (108,111 net) undeveloped acres. These interests do not expire.

 

 

We believe that we have satisfactory title to 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 crude oil and natural gas leases or capital commitments under production sharing contracts or exploration licenses. 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.

 

 

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 (1) claims from royalty owners for disputed royalty payments, (2) commercial disputes, (3) personal injury claims and (4) 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.

 

 

There were no matters submitted to a vote of our security holders during the fourth quarter of 2008.

 

The following table sets forth the names and ages (as of February 23, 2009) 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 was appointed Chairman of the Board of our company in September 2004. From October 2007 to February 5, 2009, Mr. Trice also served as President of our company. Mr. Trice announced that he will retire as our Chief Executive Officer at the annual meeting of our stockholders on May 7, 2009.

 

Lee K. Boothby was promoted to his present position on February 5, 2009. Our Board of Directors has announced that it expects to name Mr. Boothby to the additional role of Chief Executive Officer effective at the annual meeting on May 7, 2009. Prior to February 5, 2009, Mr. Boothby served as Senior Vice President — Acquisitions & Business Development since 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, and also served as Secretary of our company until May 2008.

 

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 reappointed as Vice President — Gulf of Mexico in December 2008. Prior to that, he served as Vice President — Gulf Coast since October 2007 and became the manager of our onshore Gulf Coast operations at that time. 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.

 

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

 

Gary D. Packer was promoted from Gulf of Mexico General Manager to Vice President — Rocky Mountains in November 2004. Our Board of Directors has announced that it expects to promote Mr. Packer to the position of Executive Vice President and Chief Operating Officer effective at the annual meeting of our stockholders on May 7, 2009.

 

William D. Schneider was named Vice President — Onshore Gulf Coast and International in December 2008. He has managed our international operations since May 2000.

 

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 and was named Secretary in May 2008. 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.

 

 

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 23, 2009, the last reported sales price of our common stock on the NYSE was $17.68 per share. As of that date, there were approximately 2,530 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 and our 71/8% Senior Subordinated Notes due 2018 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, 2008.

 

 

 

 

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 consists 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.