Newfield Exploration Company 10-K 2008
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission file number: 1-12534
Registrants telephone number, including area code:
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 registrants 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 registrants 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.
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.
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:
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 100200 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.
Continued Focus on Conventional Plays
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.
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 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 1012 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 5060 wells operated by others.
We are planning to operate a 35 rig drilling program throughout 2008 in our Mountain Front Wash play. We expect to drill 6070 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 1012 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 1025% 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 5070%. 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 6,0008,000 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.
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 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.
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.
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.
The information appearing in Item 1 of this Annual Report is incorporated herein by reference.
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.
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.
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.
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.
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.
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, Managements Discussion and Analysis of Financial Condition and Results of Operations, of this report.
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.
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and gas reserves. We use the full cost method of accounting for our oil and gas activities.
Oil and Gas Prices. Prices for oil and gas fluctuate widely. Oil and gas prices affect:
As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production. 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 drilling programs.
Reserve Replacement. 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 to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and gas reserves.
Significant Estimates. We believe the most difficult, subjective or complex judgments and estimates we must make in connection with the preparation of our financial statements are:
Accounting for Hedging Activities. Beginning October 1, 2005, we elected not to designate any future price risk management activities as accounting hedges. Because hedges not designated for hedge accounting are accounted for on a mark-to-market basis, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility. Please see Critical Accounting Policies and Estimates Commodity Derivative Activities.
Results of Operations
Significant Transactions. We completed several significant transactions during 2007 that affect the comparability of our results from period to period and that had a meaningful impact on our 2007 results of operations and cash flows.
Please see Note 3, Discontinued Operations, and Note 4, Oil and Gas Assets, to our consolidated financial statements appearing later in this report for a discussion regarding these transactions.
Revenues. All of our revenues are derived from the sale of our oil and gas production. The effects of the settlement of hedges designated for hedge accounting are included in revenues, but those not so designated have no effect on our reported revenues. None of our outstanding hedges are designated for hedge accounting. Please see Note 5, Commodity Derivative Instruments, to our consolidated financial statements appearing later in this report for a discussion of the accounting applicable to our oil and gas derivative contracts.
Our revenues may vary significantly from period to period as a result of changes in commodity prices or volumes of production sold. In addition, crude oil from our operations offshore Malaysia and China is produced into FPSOs and lifted and sold periodically as barge quantities are accumulated. Revenues are recorded when oil is lifted and sold, not when it is produced into the FPSO. As a result, the timing of liftings may impact period to period results.
Revenues of $1.8 billion for 2007 were 7% higher than 2006 revenues due to higher oil production and higher oil prices partially offset by lower gas production and lower gas prices. Revenues of $1.7 billion for 2006 were 5% lower than 2005 revenues due to lower gas prices and oil production partially offset by higher oil prices and increased gas production.
Domestic Production. Our 2007 domestic gas and oil production (stated on a natural gas equivalent basis) decreased 2% from 2006. Our 2007 natural gas production decreased 3% primarily as a result of the sale of our shallow water Gulf of Mexico assets in August 2007. This decrease was partially offset by an increase in production in the Mid-Continent as a result of successful drilling efforts and in the Rocky Mountains as a result of our acquisition there in June 2007. Our 2006 Gulf of Mexico production was negatively impacted (16 Bcfe) by production deferrals related to Hurricanes Katrina and Rita in 2005. Our domestic oil and condensate production increased 5% over 2006 primarily due to increased sales from our Monument Butte field.
Our 2006 domestic gas and oil production (stated on a natural gas equivalent basis) increased slightly over 2005. Our 2006 domestic natural gas production increased 4% over 2005 primarily as the result of
successful drilling efforts in the Mid-Continent partially offset by continued Gulf of Mexico production deferrals during the first half of 2006 related to the 2005 storms and natural declines in production from some fields. Our 2006 domestic oil and condensate production decreased 13% over 2005. The decrease was primarily the result of continued Gulf of Mexico production deferrals during the first half of 2006 related to the 2005 storms and natural declines in production from some fields.
International Production. Our 2007 international oil and gas production (stated on a natural gas equivalent basis) increased 106% from 2006 primarily due to the commencement of liftings in China in August 2006 and from our Abu field in Malaysia in July 2007 and the timing of liftings in Malaysia and China. Our 2006 international oil and gas production decreased 15% from 2005 due to the timing of liftings of oil production in Malaysia.
Operating Expenses. We believe the most informative way to analyze changes in our operating expenses from period to period is on a unit-of-production, or per Mcfe, basis.
Year ended December 31, 2007 compared to December 31, 2006
The following table presents information about our operating expenses for each of the years in the two-year period ended December 31, 2007.
Domestic Operations. Our total domestic operating expenses for 2007, stated on an Mcfe basis, increased 14% over 2006. The period to period change was primarily related to the following items:
International Operations. Our international operating expenses for 2007, stated on an Mcfe basis, increased 5% compared to 2006. The period to period change was primarily related to the following items:
Year ended December 31, 2006 compared to December 31, 2005
The following table presents information about our operating expenses for each of the years in the two-year period ended December 31, 2006.
Domestic Operations. Our domestic operating expenses for 2006, stated on an Mcfe basis, increased 24% over 2005. The period to period change was primarily related to the following items:
International Operations. Our international operating expenses for 2006, stated on an Mcfe basis, increased 37% over 2005. The increase was primarily related to the following items:
Interest Expense. The following table presents information about our interest expense for each of the years in the three-year period ended December 31, 2007.
The increase in gross interest expense in 2007 resulted primarily from higher average debt levels outstanding under our credit arrangements as compared to 2006. Prior to the sale of our shallow water Gulf of Mexico assets, we financed our capital shortfall and the acquisition of Stone Energys Rocky Mountain assets with cash on hand and borrowings under our credit arrangements. Following the sale, we repaid all of our
outstanding borrowings under our credit arrangements and $125 million principal amount of our 7.45% Senior Notes that became due in October 2007.
The increase in gross interest expense in 2006 resulted primarily from the April 13, 2006 issuance of $550 million principal amount of our 65/8% Senior Subordinated Notes due 2016, partially offset by the May 3, 2006 redemption of $250 million principal amount of our 83/8% Senior Subordinated Notes due 2012.
Commodity Derivative Income (Expense). The following table presents information about the components of commodity derivative income (expense) for each of the years in the three-year period ended December 31, 2007.
Taxes. The effective tax rates for the years ended December 31, 2007, 2006 and 2005 were 41%, 36% and 37%, respectively. Our effective tax rate was more than the federal statutory tax rate for all three years primarily due to state income taxes and the differences between international and U.S. federal statutory rates. Our effective tax rate for 2007 increased because $26 million of interest income on intercompany loans to our international subsidiaries was included in the determination of U.S. federal income taxes. However, the related intercompany interest expense was incurred by several of our international subsidiaries that are located in non-taxing international jurisdictions.
Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, the timing and amount of future production and future operating expenses and capital costs.
We must find new and develop existing reserves to maintain and grow production and cash flow. We accomplish this through successful drilling programs and the acquisition of properties. These activities require substantial capital expenditures. We establish a capital budget at the beginning of each calendar year. Our 2008 capital budget currently exceeds expected cash flow from operations and cash and short-term investments on hand at year end 2007 by approximately $260 million. We anticipate that the shortfall will be made up with cash and short-term investments on hand and borrowings under our credit arrangements. In the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. To the extent that we increase our capital budget during 2008, we anticipate funding these amounts with borrowings under our credit arrangements.
Credit Arrangements. In June 2007, we entered into a new revolving credit facility that matures in June 2012 and provides for initial loan commitments of $1.25 billion from a syndicate of financial institutions, led by JPMorgan Chase as agent. The loan commitments may be increased to a maximum of $1.65 billion if the existing lenders increase their loan commitments or new financial institutions are added to the facility. Subject to compliance with covenants in our credit facility that restrict our ability to incur additional debt, we also have a total of $135 million of borrowing capacity under money market lines of credit with various financial institutions. For a more detailed description of the terms of our credit arrangements, please see Note 8, Debt, to our consolidated financial statements appearing later in this report.
At February 28, 2008, we had no borrowings outstanding under our credit facility nor under our money market lines of credit and we had approximately $1.4 billion of available borrowing capacity under our credit arrangements.
Working Capital. Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements and changes in the fair value of our outstanding commodity derivative instruments. Without the effects of commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital because our capital spending generally has exceeded our cash flows from operations and we generally use excess cash to pay down borrowings under our credit arrangements.
At December 31, 2007, we had a working capital deficit of $2 million. Our current assets include $370 million of cash and short-term investments remaining from the proceeds of property sales. Our working capital position at December 31, 2007 was positively affected by a reduction in our asset retirement obligation of $30 million due to the sale of our shallow water Gulf of Mexico assets. At December 31, 2007, our working capital deficit included a short-term net derivative liability of $84 million.
This compares to a working capital deficit of $272 million at the end of 2006 and $129 million at the end of 2005. The majority of the working capital deficit at December 31, 2006 relates to the reclassification of $125 million principal amount of our 7.45% Senior Notes due October 15, 2007 as a current liability and an increase in accrued liabilities as a result of our significant capital activities near the end of 2006. The increase in accrued liabilities is due to our increased exploration and development activity and higher service costs over 2005. Our 2006 working capital deficit also includes $40 million in asset retirement obligations compared to $47 million in 2005. Our 2006 working capital includes a short-term net derivative asset of $200 million and our 2005 working capital includes a short-term net derivative liability of $89 million.
Cash Flows from Operations. Cash flows from operations (both continuing and discontinued) are primarily affected by production and commodity prices, net of the effects of settlements of our derivative contracts and changes in working capital. We also have experienced fluctuations in operating cash flows as a result of higher operating costs for all of our operations and activities associated with the 2005 storms. In August 2006, we reached an agreement with our insurance underwriters to settle all claims related to the 2005 storms (business interruption, property damage and control of well/operators extra expense) for $235 million. During 2007, we incurred $52 million of repair expenditures in excess of the insurance benefits received as compared to $17 million of uninsured repairs during 2006. These amounts are reflected as a use of operating cash flows in the respective year.
We sell substantially all of our natural gas and oil production under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future oil and natural gas production for the next 12-24 months. See Oil and Gas Hedging below. We typically receive the cash associated with accrued oil and gas sales within 45-60 days of production. As a result, cash flows from operations and income from operations generally correlate, but cash flows from operations is impacted by changes in working capital and is not affected by DD&A, writedowns or other non-cash charges or credits.
Our net cash flow from operations was $1.2 billion in 2007, a decrease of 17% compared to net cash flow from operations of $1.4 billion in 2006. Although our 2007 production volumes were impacted by our property sales, higher commodity prices offset the cash flow impact of the property sales. Realized oil and gas prices (on a natural gas equivalent basis), including the effects of hedging contracts (regardless of whether
designated for hedge accounting), increased 7% over 2006. Our working capital requirements during 2007 increased compared to 2006 as a result of increased drilling activities, the timing of payments made by us to vendors and other operators, and the timing and amount of advances received from our joint operators.
Our net cash flow from operations was $1.4 billion in 2006, a 25% increase over the prior year. The increase was primarily due to 2006 realized oil and gas prices (on a natural gas equivalent basis), including the effects of hedging contracts (regardless of whether designated for hedge accounting), which increased 9% over 2005. See Results of Operations above.
Cash Flows from Investing Activities. Net cash used in investing activities (both continuing and discontinued) for 2007 was $906 million compared to $1.7 billion for 2006.
During 2007, we:
During 2006, we:
Capital Expenditures. Our capital spending of $2.6 billion for 2007 increased 51% from our $1.7 billion of capital spending during 2006. These amounts exclude recorded asset retirement obligations of $21 million in 2007 and $11 million in 2006. Of the $2.6 billion spent in 2007, we invested $1.4 billion in domestic exploitation and development, $240 million in domestic exploration (exclusive of exploitation and leasehold activity), $736 million in acquisitions and domestic leasehold activity (including $578 million for the Rocky Mountain asset acquisition) and $236 million internationally.
Our 2006 capital spending of $1.7 billion increased 61% from our 2005 capital spending of $1.1 billion. These amounts exclude recorded asset retirement obligations of $11 million in 2006 and $44 million in 2005. During 2006, we invested $1.2 billion in domestic exploitation and development, $379 million in domestic exploration (exclusive of exploitation and leasehold activity), $71 million in other domestic leasehold activity and $133 million internationally.
We budgeted $1.6 billion for capital spending in 2008, excluding acquisitions and $113 million of estimated capitalized interest and overhead. Approximately 40% of the $1.6 billion is allocated to the Mid-Continent, 20% to the Rocky Mountains, 15% to the onshore Gulf Coast, 15% to the Gulf of Mexico and 10% to international projects. See Item 1, Business Our Properties and Plans for 2008. Since our 2008 capital budget currently exceeds forecasted net cash flow from operations, we plan to make up the shortfall with cash and short-term investments on hand and borrowings under our credit arrangements. Actual levels of capital expenditures may vary significantly due to many factors, including the extent to which properties are acquired, drilling results, oil and gas prices, industry conditions and the prices and availability of goods and services. We continue to pursue attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. Depending on the timing of an acquisition, we may spend additional capital during the year of the acquisition for drilling and development activities on the acquired properties.
Cash Flows from Financing Activities. Net cash flow used in financing activities (both continuing and discontinued) for 2007 was $79 million compared to $317 million of net cash flow provided by financing activities for 2006.
During 2007, we:
During 2006, we:
The table below summarizes our significant contractual obligations by maturity as of December 31, 2007.
Credit Arrangements. Please see Liquidity and Capital Resources Credit Arrangements above for a description of our revolving credit facility and money market lines of credit.
Senior Notes. In February 2001, we issued $175 million aggregate principal amount of our 75/8% Senior Notes due 2011. Interest on our senior notes is payable semi-annually. The notes are unsecured and unsubordinated obligations and rank equally with all of our other existing and future unsecured and unsubordinated obligations. We may redeem some or all of our senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indenture governing our senior notes contains covenants that may limit our ability to, among other things:
The indenture also provides that if any of our subsidiaries guarantee any of our indebtedness at any time in the future, then we will cause our senior notes to be equally and ratably guaranteed by that subsidiary.
During the third quarter of 2003, we entered into interest rate swap agreements that provide for us to pay variable and receive fixed interest payments and are designated as fair value hedges of a portion of our senior notes (see Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 8, Debt Interest Rate Swaps, to our consolidated financial statements).
Senior Subordinated Notes. In August 2004, we issued $325 million aggregate principal amount of our 65/8% Senior Subordinated Notes due 2014. In April 2006, we issued $550 million aggregate principal amount of our 65/8% Senior Subordinated Notes due 2016. Interest on our senior subordinated notes is payable semi-annually. The notes are unsecured senior subordinated obligations that rank junior in right of payment to all of our present and future senior indebtedness.
We may redeem some or all of our 65/8% notes due 2014 at any time on or after September 1, 2009 and some or all of our 65/8% notes due 2016 at any time on or after April 15, 2011, in each case, at a redemption price stated in the applicable indenture governing the notes. We also may redeem all but not part of our 65/8% notes due 2014 prior to September 1, 2009 and all but not part of our 65/8% notes due 2016 prior to April 15, 2011, in each case, at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. In addition, before April 15, 2009, we may redeem up to 35% of the original principal amount of our 65/8% notes due 2016 with net cash proceeds from certain sales of our common stock at 106.625% of the principal amount plus accrued and unpaid interest to the date of redemption.
The indenture governing our senior subordinated notes may limit our ability to, among other things:
Commitments under Joint Operating Agreements. Most of our properties are operated through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis. The joint operating agreement provides remedies to the operator if a non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses.
As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and natural gas production for the next 12-24 months to reduce our exposure to fluctuations in natural gas and oil prices. In the case of 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 drilling programs. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions. Approximately 87% of our 2007 production was subject to derivative contracts (including basis contracts). In 2006, 57% of our production was subject to derivative contracts, compared to 81% in 2005.
While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. Substantially all of our hedging transactions are settled based upon reported settlement prices on the NYMEX. Historically, a majority of our hedged natural gas and crude oil production has been sold at market prices that have had a high positive correlation to the settlement price for such hedges. With the sale of the Gulf of Mexico shelf production and the corresponding shift in the geographic distribution of our natural gas production, we have begun to utilize basis hedges to a greater extent.
The price that we receive for natural gas production from the Gulf of Mexico and onshore Gulf Coast, after basis differentials, transportation and handling charges, typically averages $0.40-$0.60 less per MMBtu than the Henry Hub Index. Realized gas prices for our Mid-Continent properties, after basis differentials, transportation and handling charges, typically average 75-85% of the Henry Hub Index. In light of potential basis risk with respect to our newly acquired Rocky Mountain assets, we have hedged the basis differential for about 50% of our estimated production from proved producing fields acquired from Stone Energy through 2012 to lock in the differential at a weighted average of $1.18 per MMBtu less than the Henry Hub Index. The price we receive for our Gulf Coast oil production typically averages about $2 per barrel below the NYMEX West Texas Intermediate (WTI) price. The price we receive for our oil production in the Rocky Mountains is currently averaging about $13-$15 per barrel below the WTI price. Oil production from the Mid-Continent typically sells at a $1.00-$1.50 per barrel discount to WTI. Oil sales from our operations in Malaysia typically sell at Tapis, which generally is consistent with WTI. Oil sales from our operations in China typically sell at $10-$12 per barrel less than WTI.
The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. At December 31, 2007, Barclays Capital, JPMorgan Chase, Citibank N.A., J Aron & Company, Bank of Montreal and Credit Suisse were the counterparties with respect to 84% of our future hedged production.
Between January 1, 2008 and February 25, 2008, we entered into the additional derivative contracts set forth below. None of these contracts have been designated for hedge accounting.
In addition, in February 2008 we paid $14.6 million to unwind and rehedge 360 MBbls of our oil contracts for January 2010 through December 2010. The three-way collar contracts that we unwound had weighted average prices of $32.00 and $50.88 per barrel for the floor and ceiling prices, respectively. These contracts had an additional put with a weighted average price of $25.00 per barrel. We rehedged these barrels for this period with a weighted average swap price of $93.40 per barrel.
Please see the discussion and tables in Note 5, Commodity Derivative Instruments, to our consolidated financial statements appearing later in this report for a description of the accounting applicable to our hedging program and a listing of open contracts as of December 31, 2007 and the estimated fair market value of those contracts as of that date.
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments as described above under Contractual Obligations.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Described below are the most significant policies we apply in preparing our financial statements, some of which are subject to alternative treatments under generally accepted accounting principles. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with the Audit Committee of our Board of Directors. See Results of Operations above and Note 1, Organization and Summary of Significant Accounting
Policies, to our consolidated financial statements for a discussion of additional accounting policies and estimates we make.
For discussion purposes, we have divided our significant policies into four categories. Set forth below is an overview of each of our significant accounting policies by category.
quantity of our proved oil and gas reserves;
costs withheld from amortization; and
future costs to develop and abandon our oil and gas properties.
Oil and Gas Activities. Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available successful efforts and full cost. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed, while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using period-end prices and costs and a 10% discount rate.
Full Cost Method. We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into cost centers (the amortization base) that are established on a country-by-country basis. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. Capitalized costs also include salaries, employee benefits, costs of consulting services and other expenses that are estimated to directly relate to our oil and gas activities. Interest costs related to unproved properties also are capitalized. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. Costs associated with production and general corporate activities are expensed in the period incurred. The capitalized costs of our oil and gas properties, plus an estimate of our future development costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Amortization is calculated separately on a country-by-country basis. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas activities.
Proved Oil and Gas Reserves. Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and gas reserves are the estimated quantities of natural gas and crude oil reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change
substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and gas prices, operating costs and expected performance from a given reservoir also will result in future revisions to the amount of our estimated proved reserves. All reserve information in this report is based on estimates prepared by our petroleum engineering staff.
Depreciation, Depletion and Amortization. Estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test writedown. To increase our domestic DD&A rate by $0.01 per Mcfe for 2007 would have required a decrease in our estimated proved reserves at December 31, 2006 of approximately 13 Bcfe. Due to the relatively small size of our international full cost pools for Malaysia and China, any decrease in reserves associated with the respective countrys full cost pool would significantly increase the DD&A rate in that country. However, since production from our international operations represented only about 6% of our consolidated production for 2007, a change in our international DD&A expense would not have materially affected our consolidated results of operations.
Full Cost Ceiling Limitation. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of costs associated with our oil and gas properties that can be capitalized on our balance sheet. If net capitalized costs exceed the applicable cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. If required, it would reduce earnings and stockholders equity in the period of occurrence and result in lower DD&A expense in future periods. The ceiling limitation is applied separately for each country in which we have oil and gas properties. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. The ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. However, we may not be subject to a writedown if prices increase subsequent to the end of a quarter in which a writedown might otherwise be required. The full cost ceiling test impairment calculations also take into consideration the effects of hedging contracts that are designated for hedge accounting. Given the fluctuation of natural gas and oil prices, it is reasonably possible that the estimated discounted future net cash flows from our proved reserves will change in the near term. If natural gas and oil prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that writedowns of our oil and gas properties could occur in the future.
At December 31, 2007, the ceiling value of our domestic oil and gas reserves was calculated based upon quoted market prices of $6.80 per MMBtu for gas and $96.01 per barrel for oil, adjusted for market differentials. Using these prices, the ceiling exceeded the net capitalized costs of our domestic oil and gas properties by approximately $1.9 billion (net of tax) at December 31, 2007.
At December 31, 2007, the ceiling with respect to our oil and gas properties in Malaysia and China exceeded the net capitalized costs of the properties by approximately $117 million and $70 million, respectively. Holding all other factors constant, if the applicable index for oil prices were to decline to approximately $70 per Bbl, it is possible that we could experience a ceiling test writedown in Malaysia. It is possible that we could experience a ceiling test writedown in China if the applicable index for oil prices were to decline to approximately $55 per Bbl, holding all other factors constant.
Costs Withheld From Amortization. Costs associated with unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, wells currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed quarterly for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred or a charge is made against earnings if the costs were incurred in a country for which a reserve base has not been established. If a reserve base for a country in which we are conducting operations has not yet been established, an impairment
requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information.
In addition, a portion of incurred (if not previously included in the amortization base) and future estimated development costs associated with qualifying major development projects may be temporarily excluded from amortization. To qualify, a project must require significant costs to ascertain the quantities of proved reserves attributable to the properties under development (e.g., the installation of an offshore production platform from which development wells are to be drilled). Incurred and estimated future development costs are allocated between completed and future work. Any temporarily excluded costs are included in the amortization base upon the earlier of when the associated reserves are determined to be proved or impairment is indicated.
Our decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involve a significant amount of judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and results of drilling on adjacent acreage. At December 31, 2007, our domestic full cost pool had approximately $1.1 billion of costs excluded from the amortization base. Because the application of the full cost ceiling test at December 31, 2007 resulted in a significant excess of the cost-center ceiling over the carrying value of our domestic oil and gas properties, inclusion of some or all of our unevaluated property costs in our amortization base, without adding any associated reserves, would not have resulted in a ceiling test writedown. However, our future DD&A rate would increase to the extent such costs are transferred without any associated reserves.
Future Development and Abandonment Costs. Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, water depth, reservoir depth and characteristics, market demand for equipment, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and abandonment costs on an annual basis, or more frequently if an event occurs or circumstances change that would affect our assumptions and estimates.
The accounting for future abandonment costs is set forth by SFAS No. 143. This standard requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
Holding all other factors constant, if our estimate of future development and abandonment costs is revised upward, earnings would decrease due to higher DD&A expense. Likewise, if these estimates are revised downward, earnings would increase due to lower DD&A expense. To increase our domestic DD&A rate by $0.01 per Mcfe for the year ended December 31, 2007 would require an increase in the present value of our estimated future development and abandonment costs at December 31, 2006 of approximately $38 million. Due to the relatively small size of our international full cost pools in Malaysia and China, a change greater than $30 million and $9 million, respectively, in future development or abandonment costs associated with the respective countrys full cost pool would increase the DD&A rate in that country by 10%. However, since production from our international operations represented only about 6% of our consolidated production for 2007, a change in our international DD&A expense would not have materially affected our consolidated results of operations.
Allocation of Purchase Price in Business Combinations. As part of our growth strategy, we actively pursue acquisitions of oil and gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair
value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. To the extent the consideration paid exceeds the fair value of the net assets acquired, we are required to record the excess as an asset called goodwill. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value allocated to recoverable oil and gas reserves and unproved properties is subject to the cost center ceiling as described under Full Cost Ceiling Limitation above. The accounting for business combinations will change in 2009. Please see New Accounting Standards below for a detailed discussion.
Goodwill of each reporting unit (each country is a separate reporting unit) is tested for impairment on an annual basis, or more frequently if an event occurs or circumstances change that would reduce the fair value of the reporting unit below its carrying amount. In making this assessment, we rely on a number of factors including operating results, business plans, economic projections and anticipated cash flows. As there are inherent uncertainties related to these factors and our judgment in applying them to the analysis of goodwill impairment, there is risk that the carrying value of our goodwill may be overstated. If it is overstated, such impairment would reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill. We elected to make December 31 our annual assessment date.
Commodity Derivative Activities. We utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future natural gas and oil production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 12-24 months. In the case of 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. We do not use derivative instruments for trading purposes. Under accounting rules, we may elect to designate those derivatives that qualify for hedge accounting as cash flow hedges against the price that we will receive for our future oil and natural gas production. To the extent that changes in the fair values of the cash flow hedges offset changes in the expected cash flows from our forecasted production, such amounts are not included in our consolidated results of operations. Instead, they are recorded directly to stockholders equity until the hedged oil or natural gas quantities are produced and sold. To the extent that changes in the fair values of the derivative exceed the changes in the expected cash flows from the forecasted production, the changes are recorded in income in the period in which they occur. Derivatives that do not qualify or have not been designated as cash flow hedges for hedge accounting are carried at their fair value on our consolidated balance sheet. We recognize all changes in the fair value of these contracts on our consolidated statement of income in the period in which the changes occur. Beginning on October 1, 2005, we elected not to designate any future price risk management activities as accounting hedges. Because derivative contracts not designated for hedge accounting are accounted for on a mark-to-market basis, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility.
In determining the amounts to be recorded for our open hedge contracts, we are required to estimate the fair value of the derivative. Our estimates are based upon various factors that include closing prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the hedge agreements and the resulting estimated future cash inflows or outflows over the lives of the hedges are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differences and interest rates. We periodically validate our valuations using independent, third-party quotations.
Stock-Based Compensation. On January 1, 2006, we adopted Financial Accounting Standards Board (FASB) Statement (SFAS) No. 123 (revised 2004) (SFAS No. 123(R)), Share-Based Payment, to account for stock-based compensation. Among other items, SFAS No. 123(R) eliminated the use of Accounting Principles Board Opinion No. 25 (APB 25), Accounting for Stock Issued to Employees, and the intrinsic value
method of accounting and requires companies to recognize in their financial statements the cost of services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. For all unvested options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, has been or will be recognized in our financial statements over the remaining vesting period. For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant or modification, has been or will be recognized in our financial statements over the vesting period. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and a lattice-based model for our performance and market-based restricted shares. Prior to the adoption of SFAS No. 123(R), we followed the intrinsic value method in accordance with APB 25 to account for stock-based compensation. See Note 10, Stock-Based Compensation, for a full discussion of our stock-based compensation.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). SFAS No. 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. In February 2008, the FASB granted a one-year deferral of the effective date of this statement as it applies to nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (e.g. those measured at fair value in a business combination and goodwill impairment). This statement is effective for all recurring measures of financial assets and financial liabilities (e.g. derivatives and investment securities) for fiscal years beginning after November 15, 2007. We will adopt the provisions of this statement for all recurring measures of financial assets and liabilities on January 1, 2008. We have completed our initial evaluation of the impact of SFAS No. 157 as it relates to our financial assets and liabilities and determined that its adoption is not expected to have a material impact on our financial position or results of operations.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (SFAS No. 141(R)). SFAS No. 141(R) replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and determines what information to disclose in the financial statements. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date.
Exploration and development and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. An overview of this regulation is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Please see the discussion under the caption We are subject to complex laws that can affect the cost, manner or feasibility of doing business in Item 1A of this report.
Federal Regulation of Sales and Transportation of Natural Gas. Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act (NGA) and by regulations and orders promulgated under the NGA by the FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
The Outer Continental Shelf Lands Act, or OCSLA, requires that all pipelines operating on or across the shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by the FERC under its OCSLA authority on gatherers and other entities outside the reach of its Natural Gas Act jurisdiction. Therefore, we do not believe that any FERC or MMS action taken under OCSLA will affect us in a way that materially differs from the way it will affect other natural gas producers, gatherers and marketers with which we compete.
On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (2005 EPA). This comprehensive act contains many provisions that will encourage oil and gas exploration and development in the U.S. The 2005 EPA directs the FERC, MMS and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA also increased civil and criminal penalties for any violations of the NGA, the Natural Gas Policy Act of 1978, and any rules, regulations or orders of the FERC up to $1 million per day per violation. The FERC issued a final rule effective January 26, 2006 that makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERCs jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. These changes resulting from the 2005 EPA have significantly expanded and strengthened oversight of natural gas markets. We believe, however, that neither the 2005 EPA nor the regulations promulgated, or to be promulgated, as a result of the 2005 EPA will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.
The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. In the past, the federal government regulated the prices at which gas could be sold. Congress removed all price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. There is always some risk, however, that Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines, and we cannot predict what future action the FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
Federal Regulation of Sales and Transportation of Crude Oil. Our sales of crude oil and condensate are currently not regulated. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of transportation service on certain petroleum products pipelines. However, we do not believe that these regulations affect us any differently than other crude oil and condensate producers.
Federal Leases. Our oil and gas leases in the Gulf of Mexico and many of our leases in the Rocky Mountains are granted by the federal government and administered by the MMS or the BLM, both federal agencies. MMS and BLM leases contain relatively standardized terms and require compliance with detailed BLM or MMS regulations and, in the case of offshore leases, orders pursuant to OCSLA (which are subject to change by the MMS). Many onshore leases contain stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the time during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban surface activity. For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the BLM or the MMS, as applicable, prior to the commencement of drilling, and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Shelf and removal of facilities. To cover the various obligations of lessees on the Shelf, the MMS generally requires that lessees
have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. We are currently exempt from the supplemental bonding requirements of the MMS. Under certain circumstances, the BLM or the MMS, as applicable, may require that our operations on federal leases be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and results of operations.
The MMS regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases provide that the MMS will collect royalties based upon the market value of oil produced from federal leases. The 2005 EPA formalizes the royalty in-kind program of the MMS, providing that the MMS may take royalties in-kind if the Secretary of the Interior determines that the benefits are greater than or equal to the benefits that are likely to have been received had royalties been taken in value. We believe that the MMSs royalty in-kind program will not have a material effect on our financial position, cash flows or results of operations.
In 2006, the MMS amended its regulations to require additional filing fees. The MMS has estimated that these additional filing fees will represent less than 0.1% of the revenues of companies with offshore operations in most cases. We do not believe that these additional filing fees will affect us in a way that materially differs from the way they affect other producers, gatherers and marketers with which we compete.
State and Local Regulation of Drilling and Production. We own interests in properties located onshore in a number of states and in state waters offshore Texas and Louisiana. Please see the table under Acreage Data in Item 2 of this report. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas.
Environmental Regulations. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are complex, and have tended to become more stringent over time. We also are subject to various environmental permit requirements. Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Moreover, some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.
The Oil Pollution Act, or OPA, imposes regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from spills in U.S. waters. A responsible party includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns strict, joint and several liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages for offshore facilities and up to $350 million for onshore facilities. Few defenses exist to the liability imposed by
OPA. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to administrative, civil or criminal enforcement actions.
OPA also requires operators in the Gulf of Mexico to demonstrate to the MMS that they possess available financial resources that are sufficient to pay for costs that may be incurred in responding to an oil spill. Under OPA and implementing MMS regulations, responsible parties are required to demonstrate that they possess financial resources sufficient to pay for environmental cleanup and restoration costs of at least $10 million for an oil spill in state waters and at least $35 million for an oil spill in federal waters.
In addition to OPA, our discharges to waters of the U.S. are further limited by the federal Clean Water Act, or CWA, and analogous state laws. The CWA prohibits any discharge into waters of the United States except in compliance with permits issued by federal and state governmental agencies. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. The OPA and CWA also require the preparation of oil spill response plans and spill prevention, control and countermeasure or SPCC plans. We have such plans in existence and are currently amending these plans or, as necessary, developing new SPCC plans that will satisfy new SPCC plan certification and implementation requirements that become effective in July 2009.
OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Shelf. Specific design and operational standards may apply to vessels, rigs, platforms, vehicles and structures operating or located on the Shelf. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial administrative, civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases.
The Resource Conservation and Recovery Act, or RCRA, generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy, the U.S. Environmental Protection Agency, also known as the EPA, and state agencies may regulate these wastes as solid wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
The Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a hazardous substance into the environment. Such responsible persons may be subject to joint and several liability under the Superfund law for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease onshore properties that have been used for the exploration and production of oil and gas for a number of years. Many of these onshore properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and any wastes that may have been disposed or released on them may be subject to the Superfund law, RCRA and analogous state laws and common law obligations, and we potentially could be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination.
The Clean Air Act (CAA) and comparable state statutes restrict the emission of air pollutants and affects both onshore and offshore oil and gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed and continues to develop more stringent regulations governing emissions of toxic air pollutants. These regulations may increase the costs of compliance for some facilities.
The Occupational Safety and Health Act (OSHA) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
International Regulations. Our exploration and production operations outside the United States are subject to various types of regulations similar to those described above imposed by the respective governments of the countries in which we operate, and may affect our operations and costs within that country. We currently have operations in Malaysia and China.
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. Actual results may vary significantly from those anticipated due to many factors, including:
All written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by such factors.
Below are explanations of some commonly used terms in the oil and gas business.
Basis risk. The risk associated with the sales point price for oil or gas production varying from the reference (or settlement) price for a particular hedging transaction.
Barrel or Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
BLM. The Bureau of Land Management of the United States Department of the Interior.
BOPD. Barrels of oil per day.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or natural gas.
Deepwater. Generally considered to be water depths in excess of 1,000 feet.
Developed acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploitation well. An exploration well drilled to find and produce probable reserves. Most of the exploitation wells we drilled in 2005, 2006 and 2007 and expect to drill in 2008 are located in the Mid-Continent or the Monument Butte field. Exploitation wells in those areas have less risk and less reserve potential and typically may be drilled at a lower cost than other exploration wells. For internal reporting and budgeting purposes, we combine exploitation and development activities.
Exploration well. A well drilled to find and produce oil or natural gas reserves that is not a development well. For internal reporting and budgeting purposes, we exclude exploitation activities from exploration activities.
Farm-in or farm-out. An agreement whereunder the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a farm-in, while the interest transferred by the assignor is a farm-out.
FERC. The Federal Energy Regulatory Commission.
FPSO. A floating production, storage and off-loading vessel commonly used overseas to produce oil from locations where pipeline infrastructure is not available.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
Gross acres or gross wells. The total acres or wells in which we own a working interest.
Infill drilling or infill well. A well drilled between known producing wells to improve oil and natural gas reserve recovery efficiency.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
MMS. The Minerals Management Service of the United States Department of the Interior.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
Net acres or net wells. The sum of the fractional working interests we own in gross acres or gross wells, as the case may be.
NYMEX. The New York Mercantile Exchange.
Probable reserves. Reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved u