UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-K

 

 

 

Commission file number: 1-12534

 

 

Registrant’s telephone number, including area code:

(281) 847-6000

 

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

 

 

Securities Registered Pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  þ      No  o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.  Yes  o      No  þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ      No  o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  þ      No  o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $6.5 billion as of June 30, 2010 (based on the last sale price of such stock as quoted on the New York Stock Exchange).

 

As of February 22, 2011, there were 134,336,678 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

 

Documents incorporated by reference: Proxy Statement of Newfield Exploration Company for the Annual Meeting of Stockholders to be held May 5, 2011, which is incorporated by reference to the extent specified in Part III of this Form 10-K.

 

 

 

TABLE OF CONTENTS

 

 

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

 

This report contains information that is forward-looking or relates to anticipated future events or results, such as planned capital expenditures, the availability and sources of capital resources to fund capital expenditures and other plans and objectives for future operations. Although we believe that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including:

 

 

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

 

PART I

 

processes, as well as sustainable and repeatable growth profiles. Our unconventional resource plays include producing positions in the Woodford Shale of Oklahoma, the Granite Wash of Texas and Oklahoma, the Uinta Basin of Utah and the Eagle Ford and Pearsall shales of southwest Texas. We also have acreage in the Marcellus Shale of Pennsylvania and the Southern Alberta Basin of Montana.

 

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 our drilling programs, a substantial majority of the wells we drilled in 2010 were lower-risk with low to moderate reserve potential. We have lower-risk drilling opportunities in the Mid-Continent, the Rocky Mountains and the shallow waters of Malaysia. In addition, we have assessment drilling in areas like the Eagle Ford and Pearsall shales and the Southern Alberta Basin. These opportunities are complemented with higher-risk, higher reserve potential exploration plays in the deepwater of the Gulf of Mexico and international. We actively look for new drilling ideas on our existing property base and on properties that may be acquired.

 

Acquisitions.   Acquisitions have consistently been a part of our strategy, particularly when entering new geographic regions. Since 2000, we have completed five significant acquisitions that led to the establishment of new focus areas onshore in the United States. We actively pursue acquisitions of proved oil and gas properties in select geographic areas, including those areas where we currently focus. The potential to add reserves through drilling 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 2010, we operated a significant portion 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 large portion of our employees’ compensation is tied to our performance.

 

 

Our 2011 capital budget is $1.7 billion, excluding $170 million of capitalized interest and overhead. Approximately two-thirds of our capital investments will be allocated to oil projects and substantially all of the remainder is planned for “liquids rich” gas plays. We expect our 2011 production to grow 8-12% over 2010 levels. Domestic oil production is expected to increase about 50% in 2011. Natural gas production is expected to remain relatively flat in 2011, despite a significant reduction in natural gas investments. Our diversified portfolio of assets provides us with flexibility in our capital allocation process. We have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations or to commodity price volatility.

 

Our estimated 2011 capital investments by area are shown in the chart below:

 

$1.7 Billion

 

Approximately 70% of our expected 2011 domestic oil and gas production is hedged. For a complete discussion of our hedging activities, a listing of open contracts as of December 31, 2010 and the estimated fair value of these contracts as of that date, see Note 4, “Derivative Financial Instruments,” to our consolidated financial statements.

 

Resource Plays

 

A key element of our strategy is to focus on domestic, unconventional resource plays of scale. These plays represent approximately 82% of our proved reserves and 90% of our probable reserves at year-end 2010.

 

Mid-Continent.   Our largest division in terms of our recent production, reserves and capital investment is the Mid-Continent. We are focused primarily in the Anadarko and Arkoma basins. In 2010, activity began to slow due to our shift from natural gas directed drilling to oil directed drilling throughout the Company. As of December 31, 2010, we owned a working interest in approximately 755,000 gross acres (approximately 410,000 net acres) and approximately 2,900 gross producing wells.

 

Woodford Shale.   Our largest single investment area over the last several years has been the Woodford Shale, located in the Arkoma Basin of southeast Oklahoma. The Woodford is primarily a dry gas shale formation that varies in thickness from 100 to 200 feet throughout our acreage. Our activity levels in the natural gas portion of the Woodford were reduced in 2010. We entered 2010 with eight rigs running and exited the year with three rigs. At year-end 2010, we owned an interest in approximately 172,000 net acres. Our average working interest is approximately 60%. Since entering the play in 2003, we have drilled more than 100 vertical wells and approximately 350 horizontal wells. In 2010, we assessed a new “oily” play in the Woodford, located primarily on the western edge of our acreage. We plan to drill additional wells in this play during 2011. In total, we plan to run two to three rigs in the Woodford during 2011.

 

Our 2010 production in the Woodford Shale was 25% higher than our 2009 production and as of December 31, 2010, our operated production was 169 MMcfe/d net.

 

We expect our natural gas production in the Woodford Shale to decline slightly in 2011 due to reduced capital investment in both our operated and non-operated drilling programs. Substantially all of our acreage is held-by-production. Our development plans for the field include drilling several thousand wells on primarily 40-acre spacing. In 2010, we continued to advance and improve this play through the drilling of longer lateral wells, repeatable drilling efficiency gains and optimization of completions. Our average lateral length increased by 25% in 2010 to approximately 6,300 feet which included several wells in excess of 10,000 feet. In 2011, we expect our average lateral length to be approximately 8,000 feet.

 

Granite Wash.   We are active in the Granite Wash play located in the Anadarko Basin of northern Texas and western Oklahoma and have more than 48,000 net acres in the play. Our largest producing field in the Granite Wash is Stiles/Britt Ranch, where we operate and own an average 75% working interest. Although we have approximately 150 producing vertical wells in Stiles/Britt Ranch, our drilling program is now dedicated to horizontal drilling. Since late 2008, we have drilled and completed 35 horizontal wells in the Granite Wash and the average initial production for these wells was approximately 16 MMcfe/d gross. During 2010, we ran three to four operated drilling rigs in the field with total daily production as of December 31, 2010 of approximately 86 MMcfe/d net. We expect to continue this level of activity in the Granite Wash, and expect our production to grow nearly 20% in 2011. We have an inventory of approximately 300 potential drilling locations in the Granite Wash.

 

Rocky Mountains.   As of December 31, 2010, we owned an interest in approximately 1.2 million gross acres (850,000 net acres) and more than 2,000 gross producing wells. Our assets are primarily oil and characterized by long-lived production. Our efforts today are focused primarily in the Uinta, Williston and Southern Alberta basins.

 

Greater Monument Butte.   Our largest asset in the Rocky Mountains is the Greater Monument Butte field area, located in the Uinta Basin of Utah. Our working interest in the region averages about 71%. We have approximately 1,200 productive oil wells in the Monument Butte Unit. Our acreage in this region is approximately 183,000 net acres. This includes over 60,000 net acres that we have added in recent years on Tribal and fee acreage north and adjacent to the Monument Butte Unit. Since 2008, we have drilled over 300 wells on the Tribal and fee acreage. Our gross production from the Greater Monument Butte field area has grown from 7,000 BOPD in 2004 to a 2010 exit rate of approximately 22,000 BOPD. In 2011, we are

planning to continue drilling a substantial portion of the acreage on 20-acre development spacing and estimate that we have thousands of remaining locations in the Greater Monument Butte field area.

 

There is a significant gas resource beneath the shallow producing oil zones at Monument Butte. In 2008, we participated in the drilling of six successful deep test wells to evaluate these deeper formations.

 

Williston Basin/Southern Alberta Basin.   We have approximately 120,000 net acres in the Williston Basin, excluding approximately 54,000 net acres in the mature Elm Coulee field. To date, we have drilled 44 successful wells with production from the Bakken and Sanish/Three Forks formations. In late 2010, we released information on two super extended 9,000 foot lateral wells (SXLs) west of the Nesson Anticline with 24 hour initial production rates averaging more than 3,300 BOEPD gross. In 2011, virtually all of our wells within our Williston Basin drilling program are expected to be SXL wells. Our production at year-end 2010 was approximately 7,000 BOEPD net. We plan to run four to six operated rigs in the Williston Basin in 2011. In late 2009, we reached an agreement with the Blackfeet Nation covering approximately 156,000 net acres in the Southern Alberta Basin of northern Montana. Including this transaction, we now have approximately 280,000 net acres in the Southern Alberta Basin. In 2010, we drilled five vertical wells and one horizontal well and assessment continues in 2011.

 

Green River Basin.   We own interests and operate our activities on approximately 3,000 net acres in the Pinedale field, located in Sublette County, Wyoming. We also have an interest in the Jonah field, located in Sublette County, Wyoming. Although we halted our activities in the Green River Basin in 2009 due to lower gas prices, we see the potential to drill additional locations as gas prices improve in the future.

 

Onshore Texas.   We have approximately 335,000 net acres in the Eagle Ford and Pearsall shales in the Maverick Basin, located in Maverick, Dimmit and Zavala counties, Texas. The acreage is prospective for multiple geologic horizons. Our initial assessment program in 2010 included 11 Eagle Ford Shale wells with lateral lengths of approximately 5,000 feet. The wells encountered light oil with API gravities ranging from 30 to 50 degrees. We now believe that substantially all of our Eagle Ford acreage in the Maverick Basin is within the oil window.

 

Appalachia.   In mid-2009, we signed a joint exploration agreement with Hess Corporation covering acreage primarily in Wayne County, Pennsylvania. We are the operator of this venture with a 50% working interest. At year-end 2010, we had leased about 35,000 net acres. This marked our entry into the Marcellus — one of the nation’s largest resource plays. The Marcellus is economically advantaged due to its close proximity to the gas markets in the northeast. To date, we have drilled three vertical geologic test wells and are currently evaluating the data. These wells have not been completed. We remain interested in the Appalachia region and continue to look for attractive opportunities to increase our ownership in the trend.

 

Conventional Plays

 

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

 

Onshore Texas.   As of December 31, 2010, we owned an interest in approximately 307,000 gross acres (195,000 net) and about 640 gross producing wells onshore Texas. In 2010, we slowed our activities in many of our conventional natural gas plays in response to lower natural gas prices. At year-end 2010, we were producing approximately 125 MMcfe/d net from our conventional onshore Texas assets. With planned decreased investments in 2011 and natural field declines, we expect production from this area to decline approximately 20% during 2011. In late 2010, we began a process to monetize certain non-strategic assets primarily from our onshore Texas region.

 

Gulf of Mexico.   Our Gulf of Mexico operations are focused on the deepwater. At year-end 2010, our production from the Gulf of Mexico was approximately 95 MMcfe/d net. In addition to our producing fields, we have three developments underway. As of December 31, 2010, we owned interests in 84 deepwater leases and approximately 350,000 net acres. We have an inventory of prospects acquired primarily through federal lease sales. Our working interests typically range from 20 to 50%. Following the 2010 Macondo incident in the Gulf of Mexico, we elected to defer our 2011 exploratory plans in the deepwater Gulf. With two deepwater developments

commencing production in 2011, we expect our Gulf of Mexico production to grow approximately 8% compared to 2010.

 

International.   Our international activities are focused in Southeast Asia. We have production and active developments offshore Malaysia and China. Our international production at year-end 2010 was approximately 19,000 BOPD net. We have an interest in approximately 2.5 million gross acres (936,000 net) offshore Malaysia and approximately 404,000 gross acres (385,000 net) offshore China. In 2011, our plans include continued development of our oil fields offshore Malaysia. During 2011, we also plan to develop our “Pearl” discovery (initial production 2013) in the Pearl River Mouth Basin of China and drill up to two exploratory wells offshore China. We expect our international production to grow moderately in 2011.

 

Reserves

 

Concentration

 

Reserves Concentration.   The table below sets forth the concentration of our proved and probable reserves, by location, and the percentage of those reserves attributable to our largest fields. Our largest fields, the Woodford Shale and Monument Butte, accounted for about 50% of the total net present value of our proved reserves at December 31, 2010.

 

 

Largest Fields.   The table below sets forth for our largest fields (those whose reserves are greater than 15% of our total proved reserves) the annual production volumes, average realized prices and related production cost structure on a per unit of production basis. For a discussion regarding our total domestic and international annual production volumes, average realized prices and related production cost structure on a per unit of production basis, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

 

Estimated Reserves

 

All reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. The preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data input into reserves forecasting and economics evaluation software, as well as multi-discipline management reviews, as described below. The technical employee responsible for overseeing the preparation of the reserves estimates has a Bachelor of Science in Petroleum Engineering, with more than 25 years of experience (including 15 years of experience in reserve estimation) and is a Registered Professional Engineer in Texas.

 

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

 

Actual quantities of reserves recovered will most likely vary from the estimates set forth below. Reserves and cash flow estimates rely on interpretations of data and require assumptions that may be inaccurate. For a discussion of these interpretations and assumptions, see “Actual quantities of oil and gas reserves and future cash flows from those reserves will most likely vary from our estimates” under Item 1A of this report. Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves and future net cash flows and discounted future net cash flows from proved reserves at December 31, 2010, 2009 and 2008 and changes in proved reserves during the last three years are contained in “Supplementary Financial Information — Supplementary Oil and Gas Disclosures — Estimated Net Quantities of Proved Oil and Gas Reserves” in Item 8 of this report. For a discussion of the significant changes in our proved reserves during 2010, please see the information set forth in “ Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proved Reserves” in Item 7 of this report.

The following table shows, by country and in the aggregate, a summary of our proved and probable oil and gas reserves as of December 31, 2010.

 

 

 

 

Proved Reserves.   Our year-end 2010 proved reserves of 3,712 Bcfe increased 3% compared to our proved reserves at year-end 2009. Our reserves consisted of 1,783 Bcfe proved developed producing, 381 Bcfe proved developed non-producing and 1,548 Bcfe proved undeveloped reserves.

 

At December 31, 2009, our estimated proved undeveloped reserves were 1,708 Bcfe. During 2010, we spent $550 million of drilling, completion and facilities-related capital to convert 262 Bcfe of our December 31, 2009 proved undeveloped reserves into proved developed reserves. During 2010, we added 414 Bcfe of new proved undeveloped reserves through drilling activities. Proved undeveloped reserve quantities were limited by the activity level of development drilling we expect to undertake during the 2011-2015 five-year period. Due to the higher margins of oil over natural gas investments, we shifted significant capital toward oil projects in our portfolio. As a result of this shift, we reclassified approximately 315 Bcfe of proved undeveloped reserves (nearly all Mid-Continent natural gas reserves) to probable reserves because the slower pace of development activity placed them beyond the five-year development horizon. Quantities of reserves that would otherwise meet the definition of proved undeveloped reserves, except for the fact that they will be developed beyond the 2011-2015 five-year horizon (1,336 Bcfe), were classified as probable reserves, in accordance with SEC regulations. As a result of the foregoing and minor performance related revisions, our proved undeveloped reserves at December 31, 2010 were 1,548 Bcfe, 99.6% of which have been included in our reserve report for less than five years. For additional information regarding the changes in our proved reserves, see “Proved Reserves” under Item 7 of this report.

 

In the years 2008-2010, we developed 17%, 11% and 13%, respectively, of our prior year-end proved undeveloped reserves. The development plans in our year-end reserve report reflect (i) the allocation of capital to projects in the first year of activity based upon the initial budget for such year and (ii) in subsequent years, the capital allocation in our five-year business plan, each of which generally is governed by our expectations for capital investment in such time period. Changes in commodity pricing between the time of preparation of the reserve report and actual investment, investment alternatives that may have been added to our portfolio of assets, changes in the availability and costs of oilfield services, and other economic factors may lead to changes in our development plans. As a result, the future rate at which we develop our proved undeveloped reserves may vary from historical development rates.

 

Probable Reserves.   Our total estimated probable reserves of 2,473 Bcfe at December 31, 2010, consisted of 34 Bcfe of developed and 2,439 Bcfe of undeveloped reserves, as compared to probable developed and undeveloped reserves at year-end 2009 of 101 Bcfe and 1,792 Bcfe, respectively.

 

At December 31, 2009, our estimated probable reserves were 1,893 Bcfe. During 2010, we converted 315 Bcfe of our December 31, 2009 probable reserves into proved developed reserves. Also during 2010, we added probable reserves of 1,025 Bcfe, which included 706 Bcfe of additions from our exploration and development activities and the reclassification of 315 Bcfe from proved undeveloped reserves (nearly all Mid-Continent natural gas reserves) to probable undeveloped reserves. Performance related revisions of previous estimates reduced probable reserves by 147 Bcfe at December 31, 2010. As a result of the foregoing and minor pricing related revisions, our probable reserves at December 31, 2010 were 2,473 Bcfe.

 

Probable undeveloped reserves of 2,439 Bcfe at year-end 2010 include 1,336 Bcfe that would otherwise meet the definition of proved undeveloped reserves, except that they will not be developed during the 2011-2015 five-year horizon. The characteristic uncertainties associated with the remaining 1,103 Bcfe of undeveloped probable reserves vary significantly between our major operating areas. These uncertainties restrain this reserve classification from becoming proved reserves due to their cumulative effect on achieving the reasonable certainty threshold required for proved reserves. These additional uncertainties include the lack of 3-D seismic control, uncertainty associated with geologic and reservoir continuity with increasing distance away from a producing well, immature portions of an existing waterflood, secondary response in areas of a field that has exhibited lower primary waterflood recoveries, incremental recovery factors and field development timing associated with regulatory and/or governmental approval.

Reserves Sensitivities.   To determine our year-end 2010 reserves estimates, we utilized the unweighted average first-day-of-the-month natural gas and crude oil prices for the prior twelve months, which was $4.38 per MMBtu and $79.42 per barrel, respectively, adjusted for market differentials.

 

The quantity of our proved reserves decreases slightly at lower crude oil prices as a result of shortening the economic life of our proved developed reserves. Our development plans would not materially change across a range of crude oil prices between $60 and $90 per barrel and, therefore, have little impact on the quantity of proved undeveloped reserves. That quantity is limited by the level of development drilling we expect to undertake during the 2011-2015 five-year period. Our proved undeveloped oil reserves are primarily in our Monument Butte field.

 

The quantity of our probable reserves changes less than 1% between a $4.00 and $5.00 per MMBtu natural gas price with no change in oil price. Using a $60 to $70 per barrel oil price range, with no change in natural gas price, the quantity of our probable reserves is relatively unchanged. Our probable reserves increase slightly at higher oil prices.

 

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

Drilling Activity

 

The following table sets forth our drilling activity for each year in the three-year period ended December 31, 2010.

 

 

 

 

We were in the process of drilling 24 gross (15.4 net) exploratory wells (includes 19 gross (11.5 net) exploitation wells) and 3 gross (2.0 net) development wells domestically at December 31, 2010. Internationally, we were drilling 1 gross (0.1 net) exploratory well in China at December 31, 2010. This well is not an exploitation well.

Productive Wells

 

The following table sets forth the number of productive oil and gas wells in which we owned an interest as of December 31, 2010 and the location of, and other information with respect to, those wells. As of December 31, 2010, we had 6 gross (6.0 net) gas wells and 5 gross (3.0 net) oil wells with multiple completions.

 

 

The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements or production sharing contracts. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions. Generally, an operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.

Acreage Data

 

As of December 31, 2010, we owned interests in developed and undeveloped oil and gas acreage 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 396,407 gross (107,246 net) undeveloped acres. These interests do not expire.

 

 

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes, development obligations under oil and gas leases or capital commitments under production sharing contracts or exploration licenses. As is customary in the industry in the case of undeveloped properties, often little investigation of record title is made at the time of acquisition. More detailed title work and investigations are made prior to the consummation of any acquisition of producing properties and before any commencement of drilling operations on undeveloped properties.

 

Substantially all of our oil and gas production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market sensitive prices. For a list of purchasers of our oil and gas production that accounted for 10% or more of our consolidated revenue for the three preceding calendar years, please see Note 1, “Organization and Summary of Significant Accounting Policies — Major Customers ,” to our consolidated financial statements. We believe that the loss of any of these purchasers would not have a material adverse effect on us because alternative purchasers are readily available with the exception of purchasers of our Monument Butte field oil production. Due to the higher paraffin content of this production, there is limited refining capacity for it. Please see the discussion under “There is limited transportation and refining capacity for our black wax crude oil, which may limit our ability to sell our current production or to increase our production at Monument Butte in the Uinta Basin” in Item 1A of this report.

 

Competition in the oil and gas industry is intense, particularly with respect to the hiring and retention of technical personnel, the acquisition of properties and access to drilling rigs and other services. For a further discussion, please see the information regarding competition set forth in Item 1A of this report.

 

As of February 22, 2011, we had 1,352 employees. All but 123 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.

 

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

 

Federal Regulation of Sales and Transportation of Natural Gas.   Our sales of natural gas are affected directly and 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 also may 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 BOEMRE 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.

 

Pursuant to authority enacted in the Energy Policy Act of 2005 (2005 EPA), FERC has promulgated anti-manipulation regulations, violations of which make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to use or employ any device, scheme, or artifice to defraud, to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or to engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any entity. Violation of this requirement, similar to violations of other NGA and FERC requirements, may be penalized by the FERC up to $1 million per day per violation. FERC may also order disgorgement of profit and corrective action. We believe, however, that neither the 2005 EPA nor the regulations promulgated by FERC 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.

 

Our sales of natural gas and crude are also subject to requirements under the Commodity Exchange Act (CEA) and regulations promulgated thereunder by the Commodity Futures Trading Commission (CFTC). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

 

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

 

Federal Regulation of Sales and Transportation of Crude Oil.   Our sales of crude oil and condensate are currently not regulated. In a number of instances, however, the ability to transport and sell such products 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.   Many of our domestic oil and gas leases are granted by the federal government and administered by the BOEMRE or the BLM, both federal agencies. BOEMRE and BLM leases contain relatively standardized terms and require compliance with detailed BLM or BOEMRE regulations and, in the case of offshore leases, orders pursuant to OCSLA (which are subject to change by the BOEMRE). Many onshore leases contain stipulations that may limit activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the timing and manner in which certain activities may be conducted or, in some cases, may prescribe no surface occupancy. For offshore operations,

lessees must obtain BOEMRE 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 BOEMRE, 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 BOEMRE 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 BOEMRE. Under certain circumstances, the BLM or the BOEMRE, 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 BOEMRE regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases provide that the BOEMRE 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 BOEMRE, providing that the BOEMRE 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 BOEMRE’s royalty in-kind program will not have a material effect on our financial position, cash flows or results of operations.

 

In 2006, the BOEMRE amended its regulations to require additional filing fees. The BOEMRE 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. 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 relating to environmental protection, including the discharge of substances into the environment, and permitting for oil and gas activities before, during or after operations begin. The cost to comply can be significant and failure to comply with these laws and regulations may result in administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or injunctive relief (including orders to cease operations). Environmental laws and regulations are complex, and have tended to become more stringent over time. Oil and gas activities, both onshore and offshore, in certain areas have been opposed by environmental groups through public comments on agency actions and through litigation. 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. Governmental action, through either legislative or administrative venues, that prohibits or restricts onshore or offshore drilling thereby changing the business climate under which we operate may result in increased costs to the oil and gas industry in general and 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 such 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 BOEMRE 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 BOEMRE 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 place and have made changes as necessary due to changes by the U.S. Environmental Protection Agency, also known as the “EPA,” and delays in EPA rulemaking. The final EPA rule was published in November 2009 and became effective on January 14, 2010, with a compliance deadline of November 2010.

 

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 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 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, and is considering the regulation of additional air pollutants and air pollutant parameters. These regulations may increase the costs of compliance for some facilities.

 

The Safe Drinking Water Act and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.

 

The National Environmental Policy Act (NEPA) requires federal agencies to consider potential environmental impacts that may result from projects they approve. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. 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.

 

Congress has been actively considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In June of 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009 although it was never passed by the U.S. Senate. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. Further, on April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On April 24, 2009, EPA responded to the Massachusetts, et al. v. EPA decision with a proposed finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. EPA published the final version of this finding on December 15, 2009, which allowed EPA to proceed with the rulemaking process to regulate greenhouse gases under the Clean Air Act. In anticipation of the finalization of EPA’s finding that greenhouse gases threaten public health and welfare, and that greenhouse gases from new motor vehicles contribute to climate change, EPA proposed a rule in September of 2009 that would require a reduction in emissions of greenhouse gases from motor vehicles and would trigger applicability of Clean Air Act permitting requirements for certain stationary sources of greenhouse gas emissions. In response to this issue, EPA also proposed a tailoring rule that would, in general, only impose greenhouse gas permitting requirements on facilities that emit more than 25,000 tons per year of greenhouse gases. Moreover, on September 22, 2009, EPA finalized a rule requiring nation-wide reporting of greenhouse gas emissions in 2011 for emissions occurring in 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year, and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any

additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.

 

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.

 

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

 

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

 

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

 

Bcf.   Billion cubic feet.

 

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

 

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

 

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

 

BOEMRE.   Bureau of Ocean Energy Management, Regulation and Enforcement of the U.S. Department of the Interior, formally known as the Minerals Management Service (MMS).

 

BOEPD.   Barrels of oil equivalent per day.

 

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 gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Exploitation well.   An exploration well drilled to find and produce probable reserves. Most of the exploitation wells we drill 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.   An exploration well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well. For internal reporting and budgeting purposes, we exclude exploitation activities from exploration activities.

 

FERC.   The Federal Energy Regulatory Commission.

 

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 gas reserve recovery efficiency.

 

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

 

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

 

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.

 

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

 

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

 

MMBtu.   One million Btus.

 

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

 

MMMBtu.   One billion 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.

 

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

 

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

 

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

 

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

 

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

 

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

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

 

Shelf.   The U.S. Outer Continental Shelf of the Gulf of Mexico. Water depths generally range from 50 feet to 1,000 feet.

 

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

 

Unconventional “resource” plays.   Plays targeting tight sand, coal bed or gas shale reservoirs. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economically.

 

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

 

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

 

 

We have substantial capital requirements to fund our business plans, and a continued slow recovery of the economy and the financial markets in 2011 or another decline or crisis as was experienced in late 2008 and 2009 could negatively impact our ability to execute our business plan.   Although we anticipate that our 2011 capital spending, excluding acquisitions, will correspond with our anticipated 2011 cash flows, we may borrow and repay funds under our credit arrangements throughout the year since the timing of expenditures and the receipt of cash flows from operations do not necessarily match. Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions, the prices and availability of goods and services and the extent to which properties are acquired. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We may have to reduce capital expenditures, and our ability to execute our business plans could be adversely affected, if (1) one or more of the lenders under our existing credit arrangements fail to honor its contractual obligation to lend to us; (2) the amount that we are allowed to borrow under our existing credit facility is reduced as a result of lower oil and gas prices, declines in reserves, lending requirements or for other reasons; or (3) our customers or working interest owners default on their obligations to us.

 

To maintain and grow our production and cash flow, we must continue to develop existing reserves and locate or acquire new reserves.   Through our drilling programs and the acquisition of properties, we strive to maintain and grow our production and cash flow. However, as we produce from our properties, our reserves decline. We may be unable to find, develop or acquire additional reserves or production at an acceptable cost, if at all. In addition, these activities require substantial capital expenditures.

 

Actual quantities of oil and gas reserves and future cash flows from those reserves will most likely 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 and probable 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 oil and gas reserves, future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses will most likely vary from our estimates, with the variability likely to be higher for probable reserves estimates. In addition, the methodologies and evaluation techniques that we use, which include the use of multiple technologies, data sources and interpretation methods, may be different than those used by our competitors. Further, reserve estimates are subject to the evaluator’s criteria and judgment and show important variability, particularly in the early stages of an oil and gas development. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of reserves to reflect 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 the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials, 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.

Our use of oil and gas price hedging contracts may limit future revenues from price increases and involves the risk that our counterparties may be unable to satisfy their obligations to us.   We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12-24 months as part of our risk management program. In the case of significant acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. Reducing our exposure to price volatility is intended to help ensure that we have adequate funds available for our capital programs and to help us manage returns on some of our acquisitions and more price sensitive drilling programs. Although the use of hedging transactions limits the downside risk of price declines, it also may limit the benefit from price increases and expose us to the risk of financial loss in certain circumstances. Those circumstances include instances where our production is less than the hedged volume or there is a widening of price basis differentials between delivery points for our production and the delivery points assumed in the hedge transaction.

 

Hedging transactions also involve the risk that counterparties, which generally are financial institutions, may be unable to satisfy their obligations to us. Although we have entered into hedging contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the hedging contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened, and it is possible that fewer counterparties will participate in future hedging transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes.

 

Federal legislation regarding derivatives could have an adverse effect on our ability and cost of entering into derivative transactions.   On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Reform Act), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation requires the Commodities Futures Trading Commission (the CFTC) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. On October 1, 2010, the CFTC introduced its first series of proposed rules coming out of the Dodd-Frank Reform Act. The effect of the proposed rules and any additional regulations on our business is currently uncertain. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users (such as us) from the requirements to post margins in connection with hedging activities. While several senators have indicated that it was not the intent of the Act to require margins from end users, the exemption is not in the act. The new requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to hedge and otherwise manage our financial and commercial risks related to fluctuations in oil and gas commodity prices. Any of the foregoing consequences would cause us to reconsider our hedging activities and may limit our ability to mitigate any fluctuations in oil and gas prices, which could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

 

There is limited transportation and refining capacity for our black wax crude oil, which may limit our ability to sell our current production or to increase our production at Monument Butte in the Uinta Basin.   Most of the crude oil we produce in the Uinta Basin is known as “black wax” because it has higher paraffin content than crude oil found in most other major North American basins. Due to its wax content, it must remain heated during shipping, so our transportation options are limited. Currently, the oil is transported by truck to refiners in the Salt Lake City area. We currently have agreements in place with area refiners that secure base load sales of substantially all of our expected production in the Uinta Basin through the end of 2011. In the current economic environment, there is a risk that they may fail to satisfy their obligations to us under those contracts. During the fourth quarter of 2008, the largest purchaser of our black wax crude oil failed to pay for certain deliveries of crude oil and filed for bankruptcy protection. Although we continue to sell our black wax crude oil to that purchaser on a short-term basis that provides for more timely cash

payments, we cannot guarantee that we will be able to continue to sell to this purchaser or that similar substitute arrangements could be made for sales of our black wax crude oil with other purchasers if desired. An extended loss of any of our largest purchasers could have a material adverse effect on us because there are limited purchasers of our black wax crude. We continue to work with refiners to expand the market for our existing black wax crude oil production and to secure additional capacity to allow for production growth. However, without additional refining capacity, our ability to increase production from the field may be limited.

 

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:

 

 

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.   In addition, potential regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. Exploration and development and the production and sale of oil 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. 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.

 

In addition, changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our customers. For example, governments around the world have become increasingly focused on climate change matters. On April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. the U.S. Environmental Protection Agency (EPA), held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On April 24, 2009, the EPA responded to the Massachusetts, et al. v. the EPA decision with a proposed finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. The EPA published the final version of this finding on December 15, 2009, which allowed the EPA to proceed with the rulemaking process to regulate greenhouse gases under the Clean Air Act. In anticipation of the finalization of the EPA’s finding that greenhouse gases threaten public health and welfare, and that greenhouse gases from new motor vehicles contribute to climate change, the EPA proposed a rule in September 2009 that would require a reduction in emissions of greenhouse gases from motor vehicles and would trigger applicability of Clean Air Act permitting requirements for certain stationary sources of greenhouse gas emissions. In 2010, the EPA promulgated regulations requiring certain facility owners, as that term is defined under 40 C.F.R. Part 98, to report on greenhouse gas (GHG) emissions from facilities subject to said regulations, which includes, in some situations, facilities involved in the production of oil and natural gas. The initial reporting required under these regulations is forthcoming and will ultimately add regulatory burdens for reporting emissions on certain industries. Generally speaking, the rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent GHG emissions per year, and to most upstream suppliers of fossil fuels and industrial GHG, as well as to manufacturers of vehicles and engines. The new regulations could impact certain facilities in which we have interests (legal, equitable, operated or non-operated) by increasing the regulatory reporting requirements.

 

Other proposed policy changes from regulatory agencies could also increase regulatory reporting requirements, such as hydraulic fracturing regulation on public lands proposed by the U.S. Department of the Interior. In addition, the U.S. Congress in the past has proposed legislation that directly impacts our industry, also covering areas such as emission reporting and reductions, the repeal of certain oil and gas tax incentives and tax deductions, and the regulation of over-the-counter commodity hedging activities. Similarly, in response to the 2010 Macondo incident in the Gulf of Mexico, the U.S. Congress was considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.

 

In January 2011, the 112th Session of Congress convened and at the time this report was prepared, no legislation was actively being considered on the topics mentioned herein; however, it is possible that similar legislation as introduced in previous sessions of Congress will be introduced. These and other potential regulations, if introduced and passed in Congress, could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows.

 

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

 

The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.   Hydraulic fracturing is a commonly used process that involves using water, sand, and certain chemicals to fracture the

hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process. Consideration for new federal regulation and increased state oversight continues to arise. To determine if these chemicals could adversely affect drinking water supplies, the EPA announced in the first quarter of 2010 its intention to conduct a comprehensive research study on the potential adverse effects that hydraulic fracturing may have on water quality and public health. The EPA has begun preparation for the study and expects to complete the study in 2012. In addition, various state-level initiatives in regions with substantial shale gas supplies may be proposed or implemented to regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.

 

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

 

Lower oil and gas prices and other factors have resulted in ceiling test writedowns in the past and may in the future result in additional ceiling test writedowns or other impairments.   We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost accounting method. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net cash flows from proved reserves. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. This is called a “ceiling test writedown.” As of December 31, 2008, we recorded a $1.8 billion ($1.1 billion after-tax) ceiling test writedown. We recorded an additional $1.3 billion ($854 million after-tax) ceiling test writedown as of March 31, 2009. Although a ceiling test writedown does not impact cash flows from operations, it does reduce our stockholders’ equity. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.

 

The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. We may experience further ceiling test writedowns or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

 

The oil and gas business involves many operating risks that can cause substantial losses, and insurance may not protect us against all of these risks.   We are not insured against all risks. Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:

 

 

 

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

 

 

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

 

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

 

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

 

The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.   The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. We deliver oil and gas through gathering systems and pipelines that we do not own. The lack of availability of capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through some firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical or other reasons, or may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition, results of operations and cash flows.

 

Exploration in deepwater involves significant financial risks, and we may be unable to obtain the drilling rigs or support services necessary for our deepwater drilling and development programs in a timely manner or at acceptable rates.   Much of the deepwater play lacks the physical and oilfield service infrastructure necessary for production. As a result, development of a deepwater discovery may be a lengthy process and requires substantial capital investment, and it is difficult to estimate the timing of our production. Because of the size of significant projects in which we invest, we may not serve as the operator. 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 or lead to unexpected future losses.

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

 

 

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

 

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.

 

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 remains strong. We are likely to continue to experience increased costs to attract and retain these professionals.

 

There is competition for available oil and gas properties.   Our competitors include major oil and gas companies, independent oil and gas companies and financial buyers. Some of our competitors may have greater and more diverse resources than we do. High commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties.

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

 

 

 

 

 

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

 

Lee K. Boothby was promoted to the position of President on February 5, 2009 and to the additional role of Chief Executive Officer on May 7, 2009. Our Board of Directors also has named Mr. Boothby to the additional role of Chairman of the Board, effective May 7, 2010. Prior to February 5, 2009, Mr. Boothby served as Senior Vice President — Acquisitions & Business Development since October 2007. He managed our Mid-Continent operations from February 2002 to October 2007, and was promoted from General Manager to Vice President in November 2004.

 

Gary D. Packer was promoted to the position of Executive Vice President and Chief Operating Officer on May 7, 2009. Prior thereto, he was promoted from Gulf of Mexico General Manager to Vice President — Rocky Mountains in November 2004.

 

Terry W. Rathert was promoted from Senior Vice President to Executive Vice President on May 7, 2009 and previously was promoted from Vice President to Senior Vice President in November 2004. He also served as Secretary of our company until May 2008.

 

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.

 

Daryll T. Howard was promoted to the position of Vice President — Rocky Mountains on May 7, 2009. Mr. Howard joined Newfield in 1996. Prior to his promotion on May 7, 2009, Mr. Howard served as East Team Rocky Mountain Asset Manager since June 2008. Prior thereto, Mr. Howard assisted in establishing Newfield’s Malaysia office and was instrumental in the success and growth of Newfield’s international operations. Mr. Howard also previously held several positions of increasing breadth and responsibility in Newfield’s Gulf of Mexico organization.

 

John H. Jasek was reappointed as Vice President — Onshore Gulf Coast on February 15, 2011. Prior to that, he was reappointed as Vice President — Gulf of Mexico in December 2008. Mr. Jasek served as Vice President — Gulf Coast from October 2007 until December 2008 while also serving as the manager of our onshore Gulf Coast operations. He previously managed our Gulf of Mexico operations from March 2005 until October 2007, and was promoted from General Manager to Vice President in November 2006. Prior to March 2005, he was a Petroleum Engineer in the Western Gulf of Mexico.

 

William D. Schneider was appointed Vice President — Gulf of Mexico and International on February 15, 2011. Prior to that, he served as Vice President — Onshore Gulf Coast and International from December 2008 until February 2011. He has managed our international operations since May 2000.

 

John D. Marziotti was promoted to General Counsel in August 2007 and was named Secretary in May 2008. From November 2003, when he joined our company, until August 2007 he held the position of Legal Counsel. Prior to joining us, he was a shareholder of the law firm of Strasburger & Price, LLP.

 

 

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:

 

 

Peer Group.   Our peer group consists of Cabot Oil & Gas Corporation, Cimarex Energy Company, Denbury Resources Inc., EXCO Resources, Inc., Forest Oil Corporation, Noble Energy, Inc., Petrohawk Energy Corporation, Pioneer Natural Resources Company, Plains Exploration & Production Company, Range Resources Corporation, SandRidge Energy, Inc., Southwestern Energy Company and Ultra Petroleum Corp.