Plains Exploration & Production Company 10-K 2008
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Amendment No. 1
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-31470
PLAINS EXPLORATION & PRODUCTION COMPANY
(Exact name of registrant as specified in its charter)
700 Milam Street, Suite 3100
Houston, Texas 77002
(Address of principal executive offices)
(Registrant's telephone number, including area code)
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 ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ 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 ¨
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 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. ¨
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):
Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ
On January 31, 2008, there were 112.8 million shares of the registrant's Common Stock outstanding. The aggregate market value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $3.4 billion on June 29, 2007 (based on $47.81 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange on such date).
DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the Annual Report on Form 10-K is incorporated by reference to the registrant's definitive proxy statement filed pursuant to Regulation 14A for the registrant's 2008 Annual Meeting of Stockholders.
2007 ANNUAL REPORT ON FORM 10-K/A
Table of Contents
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K/A includes forward-looking information regarding Plains Exploration & Production Company that is intended to be covered by the safe harbor for forward-looking statements provided by the Private Securities Litigation Reform Act of 1995. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as will, would, should, plans, likely, expects, anticipates, intends, believes, estimates, thinks, may, and similar expressions, are forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, there are risks, uncertainties and other factors that could cause actual results to be materially different from those in the forward-looking statements. These factors include, among other things:
All forward-looking statements in this report are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report and our other filings with the Securities and Exchange Commission. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. Except for any obligation to disclose material information under the federal securities laws, we do not intend to update these forward-looking statements and information. See Item 1A "Risk Factors and Item 7 Managements Discussion and Analysis of Financial Condition and Results of OperationsCritical Accounting Policies and Factors That May Affect Future Results in this report for additional discussions of risks and uncertainties.
This Amendment No. 1 to annual report on Form 10-K/A (Form 10-K/A) is being filed to amend the Companys annual report on Form 10-K for the year ended December 31, 2007, which was originally filed with the SEC on February 27, 2008 (Original Form 10-K). Accordingly, pursuant to rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of Items 1 and 2 of Part I, as amended, as well as currently dated certifications. Unaffected items have not been repeated in this Form 10-K/A.
We are filing this Form 10-K/A for the purpose of amending the disclosure contained in Items 1 and 2 of Part I, Business and Properties.
This amendment does not reflect events occurring after the filing of the Original Form 10-K, and does not modify or update the disclosures therein in any way other than as required to reflect the amendments as described above and set forth below.
We are an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas properties primarily in the United States. We own oil and gas properties with principal operations in:
Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. In addition to the assets in our principal focus areas listed above, we also have interests in exploration prospects offshore New Zealand and Vietnam. We use derivative contracts to manage our exposure to commodity price risk.
Oil and Gas Reserves
As of December 31, 2007, we had estimated proved reserves of 689.9 MMBOE, of which 63% was comprised of oil and 51% was proved developed. We have a total proved reserve life of approximately 18 years and a proved developed reserve life of approximately 9 years. We believe our long-lived, low production decline reserve base combined with our active risk management program should provide us with relatively stable and recurring cash flow. As of December 31, 2007, and based on year-end 2007 reference prices as adjusted for area and quality differentials, our reserves had a standardized measure of $7.6 billion. Our pro forma proved reserves were 577.1 MMBOE after adjusting for the $1.75 billion asset divestments that have or are expected to close in the first quarter of 2008. See Divestments.
The following table sets forth certain information with respect to our reserves that for 2007 are based upon (1) reserve reports prepared by the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc. and Ryder Scott Company L.P. and (2) reserve volumes prepared by us and audited by Ryder Scott and Miller and Lents, Ltd. For 2007, the independent petroleum consulting firms prepared 80% of the reserve volumes, we prepared 19% of the reserve volumes, which the independent petroleum consulting firms audited, and we prepared 1% of the reserve volumes, which were not audited by an independent petroleum consulting firm. In 2006 and 2005, 100% of our reserves were based on reserve reports prepared by Netherland, Sewell & Associates, Inc. The reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of year-end prices for each year, held constant throughout the projected reserve life.
42% of our proved undeveloped reserves are scheduled for development beyond five years and 41%, or $1,603 million, of our future estimated capital to develop proved undeveloped reserves is associated with those reserves. Our development pace takes into consideration the characteristics and location of each field while emphasizing minimal impact on the surrounding communities as well as high safety standards. We believe that our historical and forecasted pace of development strikes an appropriate balance between developing our proved reserves and our low risk unproved reserve potential in order to generate steady growth for both production and proved reserves while maximizing the value of our entire portfolio.
The following table sets forth certain information with respect to the total proved undeveloped reserves that were converted to proved developed status over the last five years.
During the three-year period ended December 31, 2007, we participated in 76 exploratory wells, of which 54 were successful, and 625 development wells, 615 of which were successful. During this period, we incurred aggregate oil and gas acquisition, development and exploration costs of $7.8 billion, approximately 89% of which was for acquisition and development activities. During this period, proved reserve additions totaled 409 MMBOE. Reserve additions and the number of wells drilled do not include any amounts attributable to the two deepwater Gulf of Mexico discoveries that were sold to Statoil Gulf of Mexico LLC in November 2006 prior to the wells being completed and any related reserve additions being recognized. Costs include expenditures related to these discoveries. See Divestments. Approximately 51% of our reserves at December 31, 2007 are classified as proved developed compared to 52% at December 31, 2006.
There are numerous uncertainties inherent in estimating quantities and values of proved reserves, and in projecting future rates of production and timing of development expenditures. Many of the factors that impact these estimates are beyond our control. Reservoir engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure shown above represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.
The reserve documentation and calculations for all of our reserves are reviewed both by our internal engineers and independent third party engineers each year. During this process all performance projections are updated and revised where appropriate, all new well control and petrophysical data acquired is incorporated into our estimated ultimate recovery and remaining reserve calculations, and the remaining proved reserves are redistributed among proved developed and proved undeveloped categories where appropriate. This insures forecasts of proved undeveloped reserves represent incremental capture and not acceleration. Our drilling activity includes a significant number of wells that were not classified as proved undeveloped in the previous years reserve report and we forecast this trend to continue as we have a substantial inventory of low risk unproved locations in addition to proved drilling locations.
In accordance with SEC guidelines, the reserve engineers estimates of future net revenues from our properties, and the present value of the properties, are made using oil and gas sales prices in
effect as of the dates of such estimates and are held constant throughout the life of the properties, except where the guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations but excluding the effect of any derivatives we have in place. Historically, the prices for oil and gas have been volatile and are likely to continue to be volatile in the future.
Since December 31, 2006, we have not filed any estimates of total net proved oil or gas reserves with any federal authority or agency other than the SEC.
We intend to be opportunistic in pursuing selective acquisitions of oil or gas properties or exploration projects. We will consider opportunities located in our current core areas of operation as well as projects in other areas that meet our investment criteria.
In November 2007, we acquired Pogo Producing Company for approximately 40 million shares of common stock and approximately $1.5 billion in cash. Pogo was engaged in oil and gas exploration, development, acquisition and production activities on its properties primarily located in the onshore United States, Vietnam and New Zealand. We accounted for the transaction under purchase accounting rules effective November 6, 2007.
In May 2007, we acquired certain properties in the Piceance Basin from a private company for $975 million in cash and one million shares of common stock. The Piceance Basin properties include interests in oil and gas producing properties in the Mesaverde geologic section of the Piceance Basin in Colorado, plus associated midstream assets, including a 25% interest in Collbran Valley Gas Gathering, LLC (CVGG).
In April 2005 and September 2005, we acquired certain California producing oil and gas properties, primarily located in the Los Angeles and the Santa Maria Basins in two separate transactions for a total of $134 million.
On December 14, 2007, together with certain of our subsidiaries, we entered into a definitive purchase and sale agreement with a subsidiary of Occidental Petroleum Corporation (Oxy) to sell 50% of our interests in oil and gas properties located in the Permian Basin, West Texas and New Mexico, the Piceance Basin in Colorado (including a 50% interest in the entity that holds our interest in CVGG) and the Utah Overthrust exploratory prospect to Oxy for $1.55 billion in cash. We will retain 50% of our working interest in the Permian and Piceance Basin properties. The transaction effective date is January 1, 2008 and is expected to close during the first quarter of 2008 subject to customary closing conditions and adjustments.
On December 14, 2007, certain of our subsidiaries entered into a definitive purchase and sale agreement with XTO Energy Inc. to sell our oil and gas interests located in the San Juan Basin in New Mexico and in the Barnett Shale in Texas. The sale of the San Juan Basin and Barnett Shale properties closed on February 15, 2008, with an effective date of January 1, 2008, and we received $199 million of cash. We are scheduled to purchase XTO's 50% working interest in the Big Mac prospect area located on the Texas Gulf Coast for approximately $20 million during the first quarter of 2008. Subsequent to closing the transaction, we will have a 100% working interest in the Big Mac prospect area, covering approximately 50,000 net lease acres.
Proved reserves attributed to the asset divestments expected to close in the first quarter of 2008 were 112.8 MMBOE at December 31, 2007.
In November 2006, we closed the sale of non-producing oil and gas properties to Statoil. We sold Statoil our working interests in two deepwater Gulf of Mexico discoveries, Big Foot and Caesar, and one deepwater exploration prospect, Big Foot North. We received approximately $706 million in cash proceeds.
In September 2006, we closed the sale of non-strategic oil and gas properties located primarily in California and Texas to subsidiaries of Oxy for net proceeds of approximately $864 million.
In May 2005, we closed the sale to XTO of interests in producing properties located in East Texas and Oklahoma for net proceeds of approximately $341 million.
Development and Exploration
We expect to continue our reserve and production growth through the development of our existing inventory of projects in each of our primary operating areas. To complement the development activities, we expect to continue to expand on our success in exploratory drilling by taking advantage of our exploratory projects in the Gulf of Mexico, onshore Gulf Coast and Panhandle area of Texas. To implement the plans, we will focus on:
By implementing our development and exploration plan, we seek to increase cash flows and enhance the value of our asset base. In doing so, we add to and enhance our proved reserves. During the three-year period ended December 31, 2007, our additions to proved reserves, excluding reserves added as a result of acquisition activities, totaled 152 MMBOE. During this period we incurred aggregate oil and gas development and exploration costs of $1.8 billion.
Our Board of Directors has approved a $1.15 billion 2008 capital budget with approximately 65% to be utilized for production and development activities in the California, Rocky Mountains, Texas and Gulf of Mexico asset areas. Approximately 25% is intended for exploration projects primarily in the Gulf of Mexico, onshore Gulf Coast and Panhandle area of Texas. The remaining 10% is intended for estimated capitalized general and administrative and interest expense, other property and equipment and California real estate development.
Of our 2008 development spending, approximately 30% is allocated to the California oil fields located in the Los Angeles, the San Joaquin and the Santa Maria Basins. The Rocky Mountains, which includes the Piceance Basin and the Madden Field, represents approximately 15% while Texas, which primarily includes the Texas Panhandle properties, the Permian Basin and the South Texas asset areas, represents approximately 25%. The remaining development budget is allocated to the delineation of our significant 2007 Gulf of Mexico exploratory discoveries, Flatrock and Friesian.
Description of Properties
Our oil and gas operations are concentrated in the Los Angeles and San Joaquin Basins onshore California, the Santa Maria Basin offshore California, the Piceance and Wind River Basins in the Rocky Mountains, the Permian Basin in West Texas and New Mexico, the Anadarko Basin in the Texas Panhandle and the South Texas and Gulf Coast regions, including the Gulf of Mexico. We also have interests in exploration prospects offshore New Zealand and Vietnam. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential.
We continue to increase the value of our oil and gas assets through a diversified growth strategy with sustained development of our base properties in the California, Rocky Mountains, Texas and Gulf of Mexico asset areas and continued exploration primarily in the Gulf of Mexico, onshore Gulf Coast and the Panhandle area of Texas. Capital additions to our oil and gas properties were $823 million in 2007, excluding acquisitions, and are currently budgeted to be approximately $1.1 billion in 2008.
The following table sets forth information with respect to our oil and gas properties as of and for the year ended December 31, 2007:
Los Angeles Basin
We hold a 100% working interest in the majority of our Los Angeles Basin properties, including Inglewood, Las Cienegas, Montebello, Packard, and San Vicente. The LA Basin properties are characterized by light crude (18 to 29 degree API gravity), well depths ranging from 2,000 feet to over 10,000 feet and include both primary production and waterfloods.
In 2007, we spent $73 million on capital projects in the LA Basin and drilled 40 wells, including injection wells. Drilling was concentrated on waterflood projects in the Inglewood Field Vickers Rindge formation with 12 wells drilled and 10 wells in the Moynier and Rubel formations. In addition, we drilled 10 wells at Montebello and 8 wells at Las Cienegas. Our net average daily sales volume from our LA Basin properties in the fourth quarter of 2007 was 13.1 MBOE per day. In 2008, a similar development drilling program is planned.
San Joaquin Basin
Our San Joaquin Basin properties are primarily in the Cymric, Midway Sunset and South Belridge Fields. These are long-lived fields that have heavier oil (12 to 16 degree API gravity), and shallow wells (generally less than 2,000 feet) that require enhanced oil recovery techniques, including steam injection.
We spent $93 million in 2007 on capital projects in the San Joaquin Basin and drilled 118 wells, including injection wells. Drilling was concentrated in the Midway Sunset Field, where we spent $62 million and drilled 81 wells, and in the Cymric Field, where we spent $23 million and drilled 28 wells. At Midway Sunset our development and expansion program in 2007 included 45 Diatomite, 18 Marvic Spellacy, 12 Marvic, 4 Potter and 2 A-1 wells and accompanying facility expansion. In the Cymric Field we drilled 16 Diatomite and 12 Tulare wells. Our net average daily sales volume from our San Joaquin Basin properties in the fourth quarter of 2007 was 20.8 MBOE per day. Our continuous development and expansion program in 2008 includes drilling Diatomite, Marvic Spellacy and Potter wells at the Midway Sunset Field, Diatomite and Tulare wells in the Cymric Field and Tulare wells in the South Belridge Field.
Other Onshore California
We hold a 100% working interest (94% net revenue interest) in the Arroyo Grande Field located in San Luis Obispo County, California. This is a long-lived field that has heavier oil (12 to 16 degree API gravity), wells depths averaging 1,700 feet and requires continuous steam injection. In 2007, we spent $15 million on capital projects in this field and drilled 40 wells, including injection wells. Our net average daily sales volume from the Arroyo Grande Field in the fourth quarter of 2007 was 1.4 MBOE per day. We plan to continue our drilling efforts within the Arroyo Grande Field in 2008 to increase the efficiency of the recovery process.
Santa Maria Basin Offshore California
Point Arguello. We hold a 69.3% working interest (58% net revenue interest) in the Point Arguello Unit and the various partnerships owning the related transportation, processing and marketing infrastructure. Capital projects in 2007 totaled $5 million and our net average daily sales volume in the fourth quarter of 2007 was 4.6 MBOE per day. Much of the activity on this property has and will continue to concentrate on maintaining production through well workovers and recompletions.
Point Pedernales. We hold a 100% working interest (83% net revenue interest) in the Pt. Pedernales Field which includes one platform, utilized to exploit the Federal OCS Monterey Reservoir by extended reach directional wells, and support facilities which lie within the onshore Lompoc Field. In 2007 we spent $15 million on capital projects in this field. Our combined net average daily sales volume from our Pt. Pedernales and Lompoc Fields averaged 7.7 MBOE per day in the fourth quarter of 2007. Much of the activity on this property has and will continue to concentrate on maintaining production through well workovers and recompletions. In addition, we are actively pursuing obtaining leases from the California State Lands Commission for the Tranquillon Ridge Field located in state waters adjacent to the Point Pedernales Field where it can be drilled from our existing platform.
Our working interest is generally 100% in the Piceance Basin, which covers over 64,000 gross (60,000 net) acres, includes over 200 producing wells and over 3,000 additional potential drilling locations in the Mesaverde geologic section plus the associated midstream assets, including a 25% interest in CVGG. The Mesaverde geologic section is found at depths generally ranging from 6,000 feet to 10,000 feet below the surface.
In 2007, we spent $126 million on capital projects in the Piceance Basin utilizing five rigs and drilling 61 wells. Stage one of a planned expansion project of the Anderson Gulch Processing Plant on the Collbran Valley Gathering System (CVGS) was completed in late August 2007 and stage two was completed in early October 2007. Drilling was concentrated in the East Plateau, Brush Creek and
Hells Gulch Fields. Our net average daily sales volume from our Piceance Basin properties in the fourth quarter of 2007 was 8.2 MBOE per day. In 2008, we plan to continue our production and reserve development in the Brush Creek, Hells Gulch and East Plateau fields.
In December 2007, we entered into a definitive purchase and sale agreement with a subsidiary of Oxy to sell 50% of PXP's interests in our oil and gas properties located in the Piceance Basin and a 50% interest in the entity that holds our interest in CVGG. We will retain 50% of our interest in the oil and gas properties and will remain the operator. See Divestments.
Wind River Basin
We own a non-controlling interest in the Madden Unit located in central Wyoming. The Madden Unit is a federal unit operated by a third party and consists of approximately 64,104 gross acres in the Wind River Basin. PXP owns an average working interest of approximately 14%.
The Madden Unit is characterized by gas production from multiple stratigraphic horizons of the Lower Fort Union, Lance, Mesaverde and Cody sands and the Madison Dolomite. Production from the Madden Unit is typically found at depths ranging from 5,500 to 25,000 feet. Some of the gas produced from the Madden Unit requires processing at the Lost Cabin Gas Plant. PXP owns an approximate 14% interest in the Lost Cabin Gas Plant.
In 2007, subsequent to our acquisition of Pogo, we spent $0.7 million on capital projects in the Madden Unit. Our net average daily sales volume from the acquisition date to year end 2007 was 4.3 MBOE per day. We will continue to target, among other objectives, the Lower Fort Union Sands and the shallower (3,500 feet) Shotgun Sands in 2008.
In late November 2007, the combustion blower for Train III failed at the Lost Cabin Gas Plant and subsequently Train III, which processes nearly half of PXPs net share of gas from the Madden unit, was shut-in. Repairs are currently underway and production is expected to return to pre-shut-in rates during the first quarter of 2008.
San Juan Basin
Our net average daily sales volume from the acquisition date to year end 2007 was 3.0 MBOE per day. In December 2007, we announced a definitive purchase and sale agreement with XTO to sell PXP's interests in the San Juan Basin properties and in the Barnett Shale in Texas. The transaction effective date is January 1, 2008, and it closed on February 15, 2008. See Divestments.
We have interests in oil and gas properties on 385,443 gross leasehold acres located in the Permian Basin in West Texas and Southeastern New Mexico.
We entered into a definitive purchase and sale agreement in December 2007 with a subsidiary of Oxy to sell 50% of our interests in oil and gas properties located in the Permian Basin and will retain 50% of our interests in these properties. Oxy will be the operator of all the assets currently operated by PXP. See Divestments.
Our net average daily sales volume from our Permian Basin properties from the acquisition date to year end 2007 was 18.3 MBOE per day.
We expect to continue development drilling in various known fields and prospects. Drilling objectives for these wells range in vertical depth from 4,500 feet to 17,000 feet below the surface and
target numerous formations including, among others, the Grayburg, Delaware (Bell Canyon, Cherry Canyon, Brushy Canyon), Spraberry, Bone Spring, Wolfcamp, Granite Wash, Strawn, Atoka, Morrow and Mississippian formations.
We have interests in oil and gas properties on approximately 495,171 gross leasehold acres with 715 square miles of 3-D seismic located in the Anadarko Basin in the Panhandle of Texas.
Development activities are concentrated in the Turkey Track Ranch and the Courson Ranch areas located primarily in Roberts and Hutchinson Counties as well as in the Wheeler and Marvin Lake Prospects in Wheeler and Hemphill Counties. The structural and stratigraphic objectives include Cleveland Sands, Mississippian carbonates, Granite and Atoka Wash, found at varying depths.
Exploration opportunities in the Panhandle have been identified on a concentration of ranches principally located in Roberts and Hutchinson Counties. Structural objectives include the Hunton Limestone and Dolomite, the Simpson Sandstones and Dolomite and the Ellenburger Dolomite. Stratigraphic traps include the Pennsylvania Granite Wash, Morrow Channel Sands and Mississippian carbonate mounds.
We spent $13.8 million on exploration and development projects in 2007 subsequent to our acquisition of Pogo. Our net average daily sales volume from our Panhandle properties from the acquisition date to year end 2007 was 6.7 MBOE per day. In 2008, we plan to concentrate our development drilling on the Wheeler and Marvin Lake Prospects as well as additional exploration drilling at the Courson and Turkey Track Ranches.
South Texas and Gulf Coast Regions
We own interests in oil and gas properties on 41,800 gross acres with 175 square miles of 3-D seismic located in South Texas.
Development activities are primarily for gas reserves concentrated in Los Mogotes, Hundido, South Hundido and Hereford Ranch Fields located in Webb and Zapata Counties. The fields produce from the Eocene Wilcox formation, found at depths generally ranging from 7,000 to 14,000 feet below the surface.
We spent $6.5 million on exploration and development projects in this area in 2007, subsequent to our acquisition of Pogo. Our net average daily sales volume from our South Texas properties from the acquisition date to year end 2007 was 10.4 MBOE per day. In 2008, we plan to continue focusing on development in the Los Mogotes, Hundido, South Hundido and Hereford Ranch Fields.
Gulf Coast Basin
We spent $424 million in 2007 on exploration and development projects in the Gulf Coast Basin, which includes coastal onshore and offshore areas of Texas and Louisiana and the Gulf of Mexico. We participated in a total of 14 exploration wells, five of which were successful and three of which were in progress at year end. Our net average sales volume for the area was 1.9 MBOE per day in the fourth quarter of 2007.
Gulf of Mexico
We entered into an exploration agreement with McMoRan Exploration Co. in November 2006 to participate in several of their Miocene exploratory prospects for $20 million. Through year end 2007, we participated in six wells of which three were successful and two were in progress at year end, all located in the Flatrock area. The discoveries were:
Production commenced at Hurricane Deep and Flatrock in the first quarter of 2008
In the deepwater area of the Gulf of Mexico, we participated in three exploration wells, of which two were unsuccessful and the other was in progress at year-end 2007. The Vicksburg discovery well is located on De Soto Canyon Block 353 and was announced in February 2008, in which PXP has a 17.5% working interest. Additional drilling and development plans are subject to further analysis.
On Green Canyon Block 599 we have a 50% interest in the Friesian discovery well announced in November 2006. During 2008, we plan to participate in several development wells and select exploration wells in the Flatrock area and deepwater Gulf of Mexico.
Onshore and Offshore Areas of Texas and Louisiana
Breton Sound. The primarily gas-focused Breton Sound area is located east-southeast of New Orleans. We spent $28.6 million on capital projects and drilled one successful exploratory well in 2007.
Jefferson County, Texas. PXP holds interests in over 92,000 gross acres, including the Oligocene, Hackberry and Vicksburg reservoirs. We own over 275 square miles of new, proprietary 3-D seismic data and interpretation of that data has yielded a number of exploratory prospects. In December 2007 we announced a definitive purchase and sale agreement to acquire XTOs interest. The transaction is expected to close during the first quarter 2008 at which time PXP will have a 100% working interest. We expect exploratory drilling to begin in 2008.
Polk and Tyler Counties, Texas. We hold approximately 69,761 gross acres, including the Cretaceous Woodbine and Austin Chalk Formations. We own approximately 125 square miles of new, proprietary 3-D seismic data and interpretation of that data has yielded a number of exploratory prospects, which are generally 100% owned and operated by PXP.
South Louisiana. We have approximately 51,000 gross acres in central South Louisiana on which to explore for Oligocene and deeper Eocene targets. We own over 165 square miles of new 3-D seismic data in central South Louisiana and hold 100% working interest.
We have interests in approximately 930,364 gross acres with 1,885 square kilometers of 3-D seismic in the offshore Northern Taranaki Basin and approximately 5,310,000 gross acres in the offshore East Coast Basin. Prior to the Pogo acquisition, Pogo and its partners drilled one unsuccessful well in the Taranaki Basin during 2007. We anticipate drilling the next prospect in 2009.
Our interest in Block 124 covers approximately 1,480,000 gross acres offshore central Vietnam. We are currently interpreting approximately 850 square kilometers of 3-D seismic data. PXP and its partner, PetroVietnam, expect to drill an exploratory well in late 2008 or 2009.
Wyoming. PXP holds interests in approximately 58,000 gross acres in the Green River Basin. Dependent on when required permits are issued and seasonal limitations, we anticipate initiating drilling in 2009.
North Dakota. We are evaluating our Mississippian Bakken Shale unconventional resource play located in Williams and Dunn Counties. We own a 100% working interest in over 85,000 gross acres.
Utah. PXP owns a 100% working interest in approximately 71,447 gross acres. In December 2007, we announced a definitive purchase and sale agreement with Oxy to sell 50% of PXPs interest in this leasehold.
Southwest Indiana. The Company owns a 50% working interest in a Devonian New Albany Shale unconventional resource play that an industry partner operates. Approximately 237,500 gross acres are under lease. We are evaluating drilling opportunities and development plans.
Texas. PXP owns a 75% working interest in 8,000 gross acres of leasehold in Jack and Wise Counties in the Barnett Shale Trend. In December 2007, we announced a definitive purchase and sale agreement with XTO to sell PXP's interests in these properties. The sale closed on February 15, 2008.
Acquisition, Exploration and Development Expenditures
The following table summarizes the costs incurred during the last three years for our acquisition, exploration and development activities.
Development costs include expenditures of $109 million in 2007, $128 million in 2006 and $114 million in 2005 related to the development of proved undeveloped reserves included in our proved oil and gas reserves at the beginning of each year. Development costs also include capital costs required to maintain our proved developed producing reserves.
Production and Sales
The following table presents information with respect to oil and gas production attributable to our properties, the revenues we derived from the sale of this production, average sales prices we realized and our average production expenses during the years ended December 31, 2007, 2006 and 2005.
See Item 7 Managements Discussion and Analysis of Financial Condition and Results of OperationsResults of Operations for cash payments related to our derivatives.
Product Markets and Major Customers
Our revenues are highly dependent upon the prices of, and demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations and depend on numerous factors beyond our control, including location and quality differentials, seasonality, economic conditions, foreign imports, political conditions in other oil-producing and gas-producing countries, the actions of OPEC, and domestic government regulation, legislation and policies. Decreases in oil and gas prices have had, and could have in the future, an adverse effect on the carrying value and volumes of our proved reserves and our revenues, profitability and cash flow.
We use various derivative instruments to manage our exposure to commodity price risks. Derivatives provide us protection on the sales revenue streams if prices decline below the prices at which the derivatives are set. However, ceiling prices in derivatives may result in us receiving less
revenue on the volumes than would be received in the absence of the derivatives. Our derivative instruments currently consist of crude oil purchased put option contracts and oil and gas price collar contracts entered into with financial institutions.
A substantial portion of our oil and gas reserves are located in California and approximately 42% of our production is attributable to heavy crude (generally 21 degree API gravity crude oil or lower). The market price for California crude oil differs from the established market indices in the U.S., due principally to the higher transportation and refining costs associated with heavy oil.
Our heavy crude is primarily sold to ConocoPhillips under a 15-year contract which expires on December 31, 2014. This contract provides for pricing based on a percentage of the NYMEX crude oil price for each type of crude oil that we produce and deliver to ConocoPhillips in California. This percentage may be renegotiated every two years, and the current percentage rates were renegotiated at the end of 2007. During 2007, we received approximately 83% of the NYMEX index price for crude oil sold under the ConocoPhillips contract, representing approximately 37% of our total crude oil production. Effective January 1, 2008, we will receive approximately 88% of the NYMEX index price for crude oil sold under this contract.
Approximately 24% of our crude oil production is sold through Plains Marketing, L.P. (PMLP), which is a subsidiary of Plains All American Pipeline, L.P., with 42% sold under contracts that provide for NYMEX less a fixed price differential (currently averaging NYMEX less $3.62 per barrel) and the remainder sold under contracts that provide for monthly field posted prices. These contracts expire at various times through 2008. The marketing agreement with PMLP provides that PMLP will purchase for resale at market prices certain of our oil production for which PMLP charges a marketing fee.
Prices received for our gas are subject to seasonal variations and other fluctuations. Approximately 50% of our gas production is sold monthly based on industry recognized, published index pricing. The remainder is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub. In addition, the market price for our Rocky Mountain gas production differs from the Henry Hub market indices in the U.S., due principally to transportation constraints and transportation costs.
During 2007, 2006 and 2005, sales to ConocoPhillips accounted for 45%, 54% and 44%, respectively, of our total revenues and sales to PMLP accounted for 31%, 41% and 38%, respectively, of our total revenues. During such periods no other purchaser accounted for more than 10% of our total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, we do not believe that the loss of any single significant customer or contract would materially affect our business in the long-term. We believe such purchasers could be replaced by other purchasers under contracts with similar terms and conditions. However, their role as the purchaser of a significant portion of our oil production does have the potential to impact our overall exposure to credit risk, either positively or negatively, in that they may be affected by changes in economic, industry or other conditions.
Substantially all of our oil and gas production is transported by pipelines and trucks owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary decreases in a significant portion of our oil and gas production.
Productive Wells and Acreage
As of December 31, 2007, we had working interests in 4,615 gross (3,816.5 net) active producing oil wells and 1,979 gross (1,246.1 net) active producing gas wells. The following table sets forth information with respect to our developed and undeveloped acreage as of December 31, 2007:
Information with regard to our drilling activities during the years ended December 31, 2007, 2006 and 2005, is set forth below:
At December 31, 2007, there were 5 gross exploratory and 13 gross development wells (3 net exploratory and 5 net development wells) in progress.
We are in the process of pursuing surface development of portions of the following tracts of real property, some of which are used in our oil and gas operations:
In January 2006, we entered into real estate consulting agreements with Cook Hill Properties, LLC. Under the terms of the agreements, Cook Hill Properties will be responsible for creating a development plan and obtaining all necessary permits for real estate development in an environmentally responsible manner on the surface estates of our properties listed above. Cook Hill Properties is a 15% participant in the venture and can earn an additional incentive on each property.
Our objective relative to the Montebello project is to take advantage of the positioning of this site as a potential significant residential development project in the San Gabriel Valley region of Greater Los Angeles. The project is located in southeastern Los Angeles County 10 miles east of downtown Los Angeles. Our objective in Lompoc and Arroyo Grande is to provide similar sustainable development inventory to Californias Central Coast. Our Lompoc property is located midway between Santa Barbara and San Luis Obispo a few miles inland from the Pacific Ocean; our Arroyo Grande property is located in the geographically desirable region near Pismo Beach and the Edna Valley.
We are actively pursuing the entitlement process for our Montebello and Lompoc properties and are engaged in pre-entitlement activities in Arroyo Grande. Our current development plans include master planned communities with a range of housing from entry level to executive and estate homes, parks and recreational land uses.
In the course of our business, certain of our properties may be subject to easements or other incidental property rights and legal requirements that may affect the use and enjoyment of our property. In 2007, we spent approximately $11 million on our real estate projects.
Title to Properties
Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.
We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.
Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our larger competitors possess and employ financial and personnel resources substantially greater than ours. These competitors are able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for prospects and resources in the oil and gas industry.
Our operations are subject to extensive governmental regulation. Many federal, state and local legislative and regulatory bodies agencies are authorized to issue, and have issued, laws and regulations binding on the oil and gas industry and its individual participants. The failure to comply with these laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state and local laws and regulations that may affect us directly or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.
OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state and local statutes and rules that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the United States Environmental Protection Agency community-right-to know regulations, and similar state and local statutes and rules require that we maintain certain information about hazardous conditions or materials used or produced in our operations and that we provide this information to our employees, government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated conditions or substances.
MMS. The United States Minerals Management Service, or MMS, has broad authority to regulate our oil and gas operations on offshore leases in federal waters. It must approve and grant permits in connection with our exploration, drilling, development and production plans in federal waters. Additionally, the MMS has promulgated regulations requiring offshore production facilities to meet stringent engineering, construction, and environmental specifications, including regulations restricting the flaring or venting of gas, governing the plugging and abandonment of wells and controlling the removal of production facilities. Under certain circumstances, the MMS may suspend or terminate any of our operations on federal leases, as discussed in Risk FactorsGovernmental agencies and other bodies, including those in California, might impose regulations that increase our costs and may terminate or suspend our operations. The MMS has adopted regulations providing for enforcement actions, including civil penalties, and lease forfeiture or cancellation for failure to comply with approved plans for offshore operations. The MMS has also established rules governing the calculation of royalties and the valuation of oil produced from federal offshore leases and regulations regarding costs for gas transportation. Delays in the approval of plans and issuance of permits by the MMS because of staffing, economic, environmental or other reasons (or other actions taken by the MMS under its regulatory authority) could adversely affect our operations.
We acquired the now-dormant Nuevo Energy Company in May 2004. The United States Attorneys Office has notified Nuevo that it is investigating allegations that during 2000-2002, prior to the
acquisition, an unaffiliated contract operator retained by Nuevo may have falsified certain records in violation of federal laws related to equipment testing. We are cooperating with this investigation. Under certain laws, Nuevo may be held responsible for the actions of its agents. However, we do not believe that such investigation will have a material adverse effect on the Company.
Regulation of production. Oil and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling and other oil and gas operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of the spacing, plugging and abandonment of wells. Many states also restrict production to the market demand for oil and gas, and several states have indicated interest in revising applicable regulations. These regulations may limit the amount of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill. Also, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of oil, gas and natural gas liquids within its jurisdiction.
Pipeline regulation. We have pipelines to deliver our production to sales points. Our pipelines are subject to regulation by the United States Department of Transportation with respect to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. In addition, we must permit access to and copying of records, and must make certain reports and provide information, as required by the Secretary of Transportation. The states in which we have pipelines have comparable regulations. Some of our pipelines related to the Point Arguello unit and CVGG are also subject to regulation by the Federal Energy Regulatory Commission, or FERC. We believe that our pipeline operations are in substantial compliance with applicable requirements.
Sale of gas. FERC regulates interstate gas pipeline transportation rates and service conditions. Although FERC does not regulate the production of gas, the agencys actions are intended to foster increased competition within all phases of the gas industry. To date, FERCs pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.
FERC, the United States Congress or state regulatory agencies may consider additional proposals or proceedings that might affect the gas industry. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.
Environmental. Our operations and properties are subject to extensive and increasingly stringent federal, state and local laws and regulations relating to safety, health and environmental protection, including the generation, storage, handling, emission and transportation of materials and the discharge of materials into the environment. Such statutes include, but are not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, Resource Conservation and Recovery Act, Clean Air Act, Clean Water Act, and Safe Drinking Water Act. Statutes that specifically provide protection to animal and plant species and which may apply to our operations include, but are not limited to, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Endangered Species Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations promulgated there under may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities, limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas; and impose substantial liabilities for pollution resulting from our operations.
As with our industry generally, our compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, upgrade and close equipment and facilities. Although these regulations affect our capital expenditures and earnings, we believe that they do not affect our competitive position because our competitors that comply with such laws and regulations are similarly affected. Environmental laws and regulations have historically been subject to change, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. If a person violates, or is otherwise liable under, these environmental laws and regulations and any related permits, they may be subject to significant administrative, civil and criminal penalties, injunctions and construction bans or delays. If we were to discharge hydrocarbons or hazardous substances into the environment, we could incur substantial expense, including remediation costs and other liability under applicable laws and regulations, as well as claims made by neighboring landowners and other third parties for personal injury and property damage.
Permits. Our operations are subject to various federal, state and local laws and regulations that include requiring permits for the drilling of wells, maintaining bonding and insurance requirements to drill, operate, plug and abandon, and restore the surface associated with our 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, the plugging and abandonment of wells, the disposal of fluids and solids used in connection with our operations and air emissions associated with our operations. Also, we have permits from numerous jurisdictions to operate crude oil, natural gas and related pipelines and equipment that run within the boundaries of these governmental jurisdictions. The permits required for various aspects of our operations are subject to revocation, modification and renewal by issuing authorities.
Plugging, Abandonment and Remediation Obligations
Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing well bores, remove tanks, production equipment and flow lines and restore the well site. Typically when producing oil and gas assets are purchased, the purchaser assumes the obligation to plug and abandon wells that are part of such assets. However, in some instances, we receive an indemnity with respect to those costs.
Although we obtained environmental studies on our properties in California and we believe that such properties have been operated in accordance with standard oil and gas industry practices in effect at the time, certain of those properties have been in operation for over 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our onshore California properties, we received a limited indemnity for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of the purchase agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of these properties, other than our obligation to plug existing wells and those normally associated with customary oil and gas operations of similarly situated properties. Current or future local, state or federal rules and regulations may require us to spend material amounts to comply with such rules and regulations, and there can be no assurance that any portion of such amounts will be recoverable under the indemnity.
We estimate our 2008 cash expenditures related to plugging, abandonment and remediation will be approximately $11.3 million. Due to the long life of our onshore California reserve base we do not expect our cash outlays for such expenditures for these properties will increase significantly in the next several years. At the Point Arguello Unit, offshore California, the companies from which we purchased
our interests retained responsibility for the majority of the abandonment costs, including: (1) removing, dismantling and disposing of the existing offshore platforms; (2) removing and disposing of all existing pipelines; and (3) removing, dismantling, disposing and remediating all existing onshore facilities. We are responsible for our 69.3% share of other abandonment costs which primarily consist of wellbore abandonments, conductor removals and site cleanup and preparation.
In connection with the sale of certain properties offshore California in December 2004 we retained the responsibility for certain abandonment costs, including removing, dismantling and disposing of the existing offshore platforms. The present value of such abandonment costs, $42 million ($81 million undiscounted), are included in our asset retirement obligation as reflected on our consolidated balance sheet. In addition, we agreed to guarantee the performance of the purchaser with respect to the remaining abandonment obligations related to the properties (approximately $46 million). To secure its abandonment obligations the purchaser of the properties is required to periodically deposit funds into an escrow account. At December 31, 2007, the escrow account had a balance of $6 million. The fair value of our guarantee, $0.4 million, is included in Other Long-Term Liabilities in the Consolidated Balance Sheet.
As of January 31, 2008, we had 775 full-time employees, two of whom were employed in our international operations and 339 of whom were field personnel involved in oil and gas producing activities. We believe our relationship with our employees is good. None of our employees is represented by a labor union.
(a) (3) Exhibits
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.