UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

 

 

(432) 683-7443

(Registrant’s telephone number, including area code)

 

 

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 of 1933.  Yes  o      No þ

 

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  o      No þ

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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 Exchange Act).  Yes  o      No þ

 

 

Portions of the registrant’s definitive proxy statement for its 2008 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2007, are incorporated by reference into Part III of this annual report for the year ended December 31, 2007.

 

 

Table of Contents

 

Cautionary statement regarding forward-looking statements

 

This report may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this annual report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this annual report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and elsewhere in this annual report could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

 

Forward-looking statements may include statements about our:

 

 

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this annual report. We do not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this annual report or to reflect the occurrence of unanticipated events except as required by law.

 

Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this annual report are reasonable, we can give no assurance that they will be achieved. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

economic, repeatable production results. As of December 31, 2007, we held interests in 206,791 gross (94,169 net) acres in five unconventional emerging resource plays. Our positions include acreage in:

 

 

Our exploration and development budget for the year ending December 31, 2008 is approximately $250 million. We plan to spend approximately 92% of our exploration and development budget on exploration and development activities associated with our conventional properties in the Permian Basin, 2% for leasehold acquisitions and 6% for exploration activities in our unconventional emerging resource plays. If we believe circumstances merit such action, including successful results from exploratory drilling in our unconventional emerging resource plays, we may reallocate or increase our 2008 exploration and development budget.

 

On February 24, 2006, we entered into a combination agreement in which we agreed to purchase certain oil and gas properties owned by Chase Oil Corporation (“Chase Oil”), Caza Energy LLC and certain other working interest owners (which we refer to collectively as the “Chase Group”) and combine them with substantially all of the outstanding equity interests of Concho Equity Holdings Corp. to form our company. The initial closing of the transactions contemplated by the combination agreement occurred on February 27, 2006, and the members of the Chase Group that sold their working interests to us received 34,683,315 shares of our common stock and approximately $400 million in cash, and the former shareholders of Concho Equity Holdings Corp. that were a party to the combination agreement received 23,767,691 shares of our common stock. In addition, certain options held by our employees to purchase preferred and common stock of Concho Equity Holdings Corp. were converted into options to purchase 2,349,113 shares of our common stock. The oil and gas properties contributed to us by the Chase Group (which we refer to as the “Chase Group Properties”) represented approximately 81% of our PV-10 as of December 31, 2007. The executive officers of Concho Equity Holdings Corp. became the executive officers of our company at the closing of the combination transaction. We have accounted for the combination transaction as a reorganization of our company, such that Concho Equity Holdings Corp. is now our wholly owned subsidiary, and a simultaneous acquisition by our company of the assets contributed by the Chase Group.

 

The following table sets forth information with respect to wells drilled during the periods indicated and does not include wells drilled on the oil and gas properties we acquired from the Chase Group prior to the combination

transaction. This information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

 

 

 

 

As of December 31, 2007, we had 8 gross (6.4 net) wells that were in the process of being drilled, 3 of which were development wells and 5 of which were exploratory wells.

 

We determined in January 2007 to reduce our drilling activities for the three months ended March 31, 2007. This determination was due to a decline in oil and natural gas prices in January 2007 compared to such prices in the fourth quarter of 2006, the costs of goods and services necessary for our drilling activities and the resulting effect of these circumstances on our expected cash flow for the three months ended March 31, 2007. This reduction in drilling activities resulted in a reduction in oil and gas production, revenues and cash provided by operating activities for the year ended December 31, 2007. We resumed our drilling activities in April 2007, and we expended our approved 2007 exploration and development budget of approximately $183 million before January 1, 2008.

Our Production, Prices and Expenses

 

The following table sets forth summary information concerning our production results, average sales prices and production costs for the years ended December 31, 2007, 2006 and 2005. The actual historical data in this table excludes production and related sales prices and costs attributable to the Chase Group Properties for periods prior to February 27, 2006.

 

 

 

The Permian Basin is one of the most prolific oil and gas regions in the United States, with its first commercial discovery in 1923 and cumulative production of 32.8 billion barrels of oil and 107 trillion cubic feet of gas as of December 31, 2007. Average daily production in the Permian Basin is approximately 11 billion cubic feet equivalent gas per day from approximately 121,500 active producing wells. It underlies an area of Southeast New Mexico and West Texas approximately 250 miles wide and 300 miles long. Commercial accumulations of hydrocarbons occur in multiple stratigraphic horizons, at depths ranging from approximately 1,000 feet to over 25,000 feet. This area is characterized by long life shallow decline reserves.

 

The Permian Basin is our core operating area, and, as of December 31, 2007, our estimated net proved reserves of 541 Bcfe in this basin accounted for 99% of our total estimated net proved reserves and 99% of our PV-10. As of December 31, 2007, we owned interests in 2,013 wells in the Permian Basin, of which we operated 1,029. Based on our total proved reserves as of December 31, 2007, and our 2007 production, our reserve to production ratio was 18.2 years. As of December 31, 2007, we had identified 1,653 drilling locations, with proved undeveloped reserves attributed to 623 of such locations, and 874 recompletion opportunities, with proved reserves attributed to 372 of such opportunities. During the year ended December 31, 2007, our average net daily production in the Permian Basin was 81.4 MMcfe per day.

 

Our Permian Basin operations in Southeast New Mexico represent our most significant concentration of assets and, as of December 31, 2007, our estimated proved reserves of 460.8 Bcfe in this portion of the Permian Basin accounted for 84% of our total net proved reserves and 85% of our proved PV-10. As of December 31, 2007, the wells that we operated accounted for 92% of our proved PV-10 in this core area. As of December 31, 2007, we had 1,518 producing wells in Southeast New Mexico. During the year ended December 31, 2007, our average net daily production from this area was approximately 66.4 MMcfe per day, representing 80% of our total production for that time period. We target two distinct producing areas, which we refer to herein as the Shelf Properties and the Basinal Properties. The Shelf Properties generally produce from the Yeso (Paddock and Blinebry intervals), San Andres and Grayburg formations, with producing depths generally ranging from 900 feet to 7,500 feet. The Basinal Properties generally produce from the Morrow formation, with producing depths generally ranging from 7,500 feet to 15,000 feet.

 

Our Shelf Properties represented 81% of our total PV-10 as of December 31, 2007. We acquired most of these properties from the Chase Group upon closing the combination transaction. As of December 31, 2007, we had 429.4 Bcfe of proved reserves and 1,243 producing wells in this area. As of December 31, 2007, we held interests in 100,603 gross (49,306 net) acres in this area. As of December 31, 2007, on our Shelf Properties, we had identified 1,368 drilling locations, with proved undeveloped reserves attributed to 432 of such locations, and 783 recompletion opportunities, with proved undeveloped reserves attributed to 297 of such opportunities. Average net daily production from this area for the year ended December 31, 2007, was approximately 58.5 MMcfe per day, and production from this area represented 71% of our total average daily net production for the same period. Our properties in this area are primarily located in Eddy and Lea Counties, New Mexico, along the Abo-Yeso shelf edge on the northern rim of the Delaware Basin. This east to west trending fairway produces from a succession of stacked pays. During 2007, we continued our development of the Blinebry interval of the Yeso formation, the top of which is located approximately 400 feet below the base of the Paddock interval of the Yeso formation. Our evaluation of the Blinebry interval began in late 2005. In 2007, we drilled 83 wells in the Blinebry interval, all of which have since been completed as producers. As of December 31, 2007, we were operating 5 drilling rigs on our Shelf Properties, all of which were targeting the Blinebry.

 

Included in the drilling locations we had identified as of December 31, 2007 were 672 drilling locations in the Blinebry interval, with proved undeveloped reserves attributed to 134 of such locations. Of the remaining locations, 446 of such locations are intended to evaluate both the Blinebry and the Paddock intervals, while 92 of such locations are intended to evaluate just the Blinebry interval. During the year ended December 31, 2007, we drilled 83 Blinebry wells, of which 74 were completed as producers and 9 were awaiting completion as of December 31, 2007. In addition, in September 2007 we began injecting water on our pilot waterflood covering approximately 160 acres in the Paddock interval of the Yeso formation. The Empire/Empire East and Loco Hills fields collectively comprised 74% of our Southeast New Mexico PV-10 as of December 31, 2007.

 

Empire/Empire East Field.   We are currently producing from the Yates, Morrow, Grayburg, Queen, Strawn, Wolfcamp, Seven Rivers, Yeso (Paddock and Blinebry intervals) and Abo formations. As of December 31, 2007, we had 201 Bcfe of proved reserves and 623 wells producing in the area. In addition, as of December 31, 2007, we had identified 368 drilling locations, with proved undeveloped reserves attributed to 161 of such locations, and 341 recompletion opportunities, with proved undeveloped reserves attributed to 117 of such opportunities. As of December 31, 2007, proved reserves attributable to the Empire/Empire East field had a PV-10 of $857.2 million, which represented approximately 47% of the total PV-10 attributable to our Southeast New Mexico properties. Average net daily production from this field for the year ended December 31, 2007 was approximately 25.5 MMcfe per day.

 

Loco Hills Field.   We are currently producing from the Seven Rivers, Queen, Grayburg, Morrow, Abo, San Andres and Yeso (Paddock and Blinebry intervals) formations. As of December 31, 2007, we had 254 producing wells in this field. In addition, as of December 31, 2007, we had identified 199 drilling locations, with proved undeveloped reserves attributed to 91 of such locations, and 291 recompletion opportunities, with proved reserves attributed to 112 of such opportunities. As of December 31, 2007, proved reserves attributable to the Loco Hills field had a PV-10 of $496.5 million, which represented approximately 27% of the total PV-10 attributable to our Southeast New Mexico properties. Average net daily production from this field for the year ended December 31, 2007 was approximately 21.2 MMcfe per day.

 

Our Basinal Properties in Southeast New Mexico represented approximately 4% of our total PV-10 as of December 31, 2007. As of December 31, 2007, we had 31 Bcfe of proved reserves and 275 wells in this area. As of December 31, 2007, we held interests in 68,708 gross (25,576 net) acres in this area. As of December 31, 2007, on our Basinal Properties, we had identified 98 drilling locations, with proved undeveloped reserves attributed to 58 of such locations, and 39 recompletion opportunities, with proved undeveloped reserves attributed to 34 of such opportunities. Average net daily production from this area for the year ended December 31, 2007, was approximately 7.9 MMcfe per day, and production from this area represented 10% of our total average daily net production

for the same period. The majority of our production in this region is from the Morrow formation, with significant additional contributions from the more shallow Atoka and Strawn formations. During the year ended December 31, 2007, we drilled 4 wells to the Morrow formation, of which 3 were completed as producers and 1 was a dry hole. In addition, during the year ended December 31, 2007, we recompleted 5 wells in the Morrow formation, all of which were producing as of December 31, 2007.

 

This area accounted for approximately 14% of our total proved reserves and approximately 13% of our total PV-10 as of December 31, 2007. As of December 31, 2007, we had 75 Bcfe of proved reserves and 491 wells producing in this area. In addition, as of December 31, 2007, we had identified 143 drilling locations, with proved undeveloped reserves attributed to 124 of such locations, and 52 recompletion opportunities, with proved undeveloped reserves attributed to 41 of such opportunities. During the year ended December 31, 2007, we drilled 9 wells, all of which were completed as producers as of December 31, 2007. In addition, during the year ended December 31, 2007, we commenced the recompletion of 19 wells, all of which were producing as of December 31, 2007.

 

As of December 31, 2007, we were involved in 5 unconventional emerging resource plays, with interests in 206,791 gross (94,169 net) acres. These plays are currently in various stages of maturity. As of December 31, 2007, we had an aggregate of 6.4 Bcfe of proved reserves attributed to these plays.

 

Horizontal Wolfcamp gas and oil plays are being actively exploited along the northwestern rim of the Delaware Basin in Eddy and Chaves Counties, New Mexico, with several operators producing and selling oil and gas. As of December 31, 2007, we held interests in 55,668 gross (23,699 net) acres in these plays.

 

The horizontal Wolfcamp gas play is found at depths ranging from 4,100 feet to 6,000 feet. Of our horizontal Wolfcamp acreage, 38,136 gross (10,064 net) acres are in the Wolfcamp gas play. We have tested 1 re-entry well, and have participated in the drilling of 13 horizontal exploration wells in this play.

 

The horizontal Wolfcamp oil play is found at depths ranging from 6,500 feet to 9,000 feet. Of our horizontal Wolfcamp acreage, 17,532 gross (13,635 net) acres are in the horizontal Wolfcamp oil play. We have drilled 3 wells in the oil play, 2 of which were completed as horizontal Wolfcamp oil producers, and 1 of which was completed as a vertical producer in a shallower interval.

 

As of December 31, 2007, we had 6.0 Bcfe of proved reserves attributed to the horizontal Wolfcamp gas and oil plays.

 

As of December 31, 2007, we held interests in 22,925 gross (22,155 net) acres in an unconventional shale play in Andrews County, Texas. This unconventional shale is prospective at depths of 8,000 to 10,000 feet. We drilled our first test well in the first quarter of 2008, and it is currently awaiting completion.

 

The Delaware Basin shale play is located in West Texas in a lightly explored portion of the Delaware Basin. As of December 31, 2007, we held interests in 68,814 gross (22,794 net) acres in Culberson and Reeves Counties, Texas. Both conventional and unconventional targets are prospective in this area. We have drilled 4 exploratory wells targeting the Bone Spring, Atoka, Barnett and Woodford Shales, which are found at depths ranging from 5,000 feet to 12,000 feet. Three of these wells have been deemed non-commercial. A vertical Woodford Shale completion in the fourth well tested at a rate of approximately 1 MMcf per day, and is currently flowing gas to sales at a rate of approximately 650 Mcf per day.

 

The horizontal Bakken Shale play is being developed in the North Dakota portion of the Williston Basin. This Mississippian age horizon consists of a siltstone encased within a highly organic, oil-rich shale package and is found at depths ranging from 9,000 feet to 11,000 feet. As of December 31, 2007, we had participated in 8 horizontal Bakken wells, of which 4 were producing, 3 were awaiting completion and 1 was drilling. As of December 31, 2007, we held interests in 42,362 gross (11,069 net) acres in this play, primarily in Mountrail and McKenzie Counties, North Dakota. As of December 31, 2007, we had 0.4 Bcfe of proved reserves attributed to this play.

 

As of December 31, 2007, we held interests in 17,022 gross (14,452 net) acres in the Fayetteville Shale play in Faulkner and White Counties, Arkansas. The Fayetteville Shale play in the eastern Arkoma Basin of Arkansas is the geological time equivalent to the Barnett Shale, a productive horizon in the Ft. Worth Basin. The Fayetteville Shale has production from both vertical and horizontal wells, and on our acreage position the Fayetteville Shale is found at depths ranging from 7,000 feet to 8,500 feet. We plan on drilling our initial test well in this area in 2008.

 

General.   We market our crude oil and natural gas in accordance with standard energy practices utilizing certain of our employees and independent consultants, in each case in consultation with our chief financial officer and our production engineers. The marketing effort is coordinated with our operations group as it relates to the planning and preparation of future drilling programs so that available markets can be assessed and secured. This planning also involves the coordination of procuring the physical facilities necessary to connect new producing wells as efficiently as possible upon their completion. When possible, we negotiate with our purchasers on multiple well programs in an attempt to improve our economics on such wells due to the commitment of potentially increased production volumes. Our current drilling plans consist substantially of multiple well programs.

 

Crude Oil.   We do not refine or process the crude oil we produce. The majority of our crude oil is connected directly to pipelines via gathering facilities in the respective field locations throughout Southeast New Mexico and West Texas. The oil is then delivered either to hub facilities located in Midland, Texas or Cushing, Oklahoma or to third party refineries located in Southeast New Mexico and the panhandle of Texas, with the majority of our crude oil going to a refinery in Southeast New Mexico. The remaining oil that we produce is transported by truck to various pipeline stations throughout Southeast New Mexico and West Texas. This oil is also transported to the hub facilities and refineries mentioned above. We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on a Platt’s formula which is calculated based on an intermediate posting deemed 40 degrees (typically as published by major crude oil purchasers at the Cushing, Oklahoma delivery point) for each calendar month plus the average of the Platt’s P-Plus WTI price as published monthly in the Platt’s Oilgram Price Report. This price is then adjusted for differentials based upon delivery location and oil quality.

 

Natural Gas.   When assessing the market for our natural gas we first determine the type of gas connection needed based upon the type of gas expected to be produced. We also consider any gas gathering and delivery infrastructure in the areas of our production and evaluate market options to obtain the best price reasonably available under the circumstances. We sell the majority of our gas under individually negotiated gas purchase contracts using market sensitive pricing. The majority of our gas is subject to term agreements that extend at least three years from the date of the subject contract.

 

The majority of the gas we sell is casinghead gas which is sold at the wellhead under a percentage of proceeds processing contract. The purchaser gathers our casinghead gas in the field where produced and transports it via pipeline to a gas processing plant where the liquid products are extracted. The remaining gas product is residue gas, or dry gas. Under our percentage of proceeds contract, we receive the value for the extracted liquids and the residue gas. Each of the liquid products has its own individual market and is therefore priced separately.

 

The remaining portion of our gas is dry gas which is gathered at the wellhead and delivered into the purchaser’s residue or mainline transportation system. In many cases, the gas gathering and transportation is performed by a

third party gathering company which transports the production from the production location to the purchaser’s mainline. The majority of our dry gas and residue gas is subject to term agreements that extend at least three years from the date of the subject contract.

 

We sell our oil and natural gas production principally to marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, see “Item 1A. Risk Factors — Risks Relating to Our Business — Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.”

 

For the year ended December 31, 2007, revenues from oil and natural gas sales to Navajo Refining Company, L.P. and DCP Midstream, LP, formerly Duke Energy Field Services, accounted for approximately 60% and 23%, respectively, of our total operating revenues. While the loss of either of these purchasers may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of either of these purchasers would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions.

 

The oil and natural gas industry in the regions in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated oil companies. We primarily encounter significant competition in acquiring properties, contracting for drilling and workover equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

 

We are also affected by competition for drilling rigs and the availability of related equipment. The oil and natural gas industry periodically experiences shortages of drilling and workover rigs, equipment, pipe, materials and personnel, which can delay developmental drilling, workover and exploitation activities and cause significant price increases. The current shortage of personnel has also made it difficult to attract and retain personnel with experience in the oil and gas industry and has caused us to increase our general and administrative budget. We are unable to predict the nature, timing or duration of any such shortages.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.

 

Regulation of transportation of oil.   Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

 

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the “FERC,” regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be just and reasonable based on cost, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system that enables interstate oil pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC’s indexing

methodology is subject to review every five years; the current methodology is expected to remain in place through June 30, 2011. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

 

Regulation of transportation and sale of natural gas.   Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

 

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

 

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

 

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

 

Regulation of Production.   The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

 

General.   Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

 

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

 

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.

 

Waste Handling.   The Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or “EPA”, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste

provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act.   The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, 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, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

 

Water Discharges.   The Federal Water Pollution Control Act, or the “Clean Water Act”, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

Air Emissions.   The federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

 

In response to recent studies suggesting that emissions of certain gases, referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere, the current session of the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions — a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. Debate and a possible vote on this bill by the full Senate are anticipated to occur before mid-year 2008. In addition, at least one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels we produce.

Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, and certain provisions of the Clean Air Act, the EPA may regulate carbon dioxide and other greenhouse gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has publicly stated its goal of issuing a proposed rule to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels but the timing for issuance of this proposed rule is unsettled as the agency reviews its mandates under the Energy Independence and Security Act of 2007, which includes expanding the use of renewable fuels and raising the corporate average fuel economy standards. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state laws requiring adoption of a stringent greenhouse gas control program or imposing restrictions on emissions of carbon dioxide in areas of the United States in which we conduct business could adversely affect our cost of doing business and demand for our products.

 

National Environmental Policy Act.   Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

 

OSHA and Other Laws and Regulation.   We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA”, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

 

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2007. Additionally, as of the date of this annual report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2008. However, we cannot assure you that the passage of more stringent laws or regulations in the future will not have an negative impact on our financial position or results of operation. For instance, the New Mexico Oil Conservation Division is considering amending or replacing an existing rule regulating the permitting, construction, operation and closure of oilfield pits at well sites in New Mexico. If the agency adopts a new or revised pit rule that imposes stricter requirements on the construction and use of oilfield pits, then it is possible that the cost to operate our wells in New Mexico could increase.

 

As of December 31, 2007, we employed 113 employees, including 44 in drilling and production, 16 in financial and accounting, 20 in land, 14 in exploration, 7 in reservoir engineering and 12 in administration. Of these, 86 worked in our Midland, Texas headquarters and 27 were in our field operations. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. We also utilize the services of independent contractors to perform various field and other services.

 

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”). The public may read and copy any materials that we file with or furnish to the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including Concho, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

 

We also make available free of charge through our internet website (www.conchoresources.com) our annual report, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

 

 

Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can affect the value of our common stock.

 

Furthermore, recent oil prices have been high compared to historical prices and have been particularly volatile. For example, the NYMEX crude oil price per Bbl was $95.98, $61.15 and $61.04 as of December 31, 2007, 2006 and 2005, respectively. In addition, natural gas prices have been subject to significant fluctuations during the past several years. For example, the NYMEX natural gas Henry Hub spot price per MMbtu was $6.80, $5.64 and $10.08 as of December 31, 2007, 2006 and 2005, respectively.

 

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could cause our expenses to increase or our cash flows and production volumes to decrease.

 

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “— Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.” Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

 

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially reduce the estimated quantities and present value of our reserves.

 

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many estimates, including estimates based upon assumptions relating to economic factors. Any significant inaccuracies in these interpretations or estimates could materially reduce the estimated quantities and present value of reserves shown in this annual report. See “Item 2. Properties — Our Oil and Natural Gas Reserves” for information about our oil and natural gas reserves.

 

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and

reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, the amount and timing of capital expenditures, taxes and the availability of funds.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this annual report. For example, in connection with the preparation of our total estimated net proved reserves as of December 31, 2007, we revised our estimated natural gas equivalent reserves downward by 19,168 MMcfe from our previous estimates. This reduction in reserves was primarily due to reduction in forecasted future performance and other revisions to proved properties existing at December 31, 2006, conversion of producing wells to water injection wells on a pilot waterflood on our Shelf Properties, and dry holes drilled during 2007. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors.

 

It should not be assumed that the present value of future net revenues from our proved reserves referred to in this annual report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. The present value of future net revenues from our proved reserves as of December 31, 2007 referred to in this annual report was based on a $92.50 per Bbl Plains Marketing, L.P. West Texas Intermediate posted price for oil and a $6.80 per MMBtu Henry Hub spot price for natural gas. If oil prices were $1.00 per Bbl lower than the price we used, our PV-10 as of December 31, 2007, would have decreased from $2,138.5 million to $2,116.1 million. If natural gas prices were $0.10 per Mcf lower than the price we used, our PV-10 as of December 31, 2007, would have decreased from $2,138.5 million to $2,127.7 million. Any adjustments to the estimates of proved reserves or decreases in the price of oil or natural gas may decrease the value of our common stock.

 

Almost all of our producing properties are located in the Permian Basin region of Southeast New Mexico and West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, a substantial portion of our proved reserves as of December 31, 2007, are from a single producing horizon within this area.

 

Our producing properties are geographically concentrated in the Permian Basin region of Southeast New Mexico and West Texas. At December 31, 2007, approximately 99% of our PV-10 was attributable to properties located in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from these wells caused by significant governmental regulation, processing or transportation capacity constraints, market limitations, curtailment of production or interruption of the processing or transportation of oil and natural gas produced from the wells in these areas.

 

In addition to the geographic concentration of our producing properties described above, approximately 58% of our proved reserves as of December 31, 2007, were attributable to the Yeso formation, which includes both the Paddock and Blinebry intervals, underlying our oil and gas properties located in Southeast New Mexico. This concentration of assets within one producing horizon exposes us to risks such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within the field. Furthermore, we are in the process of drilling and completing wells in the Blinebry interval (the lower member of the Yeso formation), which lies beneath the Paddock interval on certain of our properties located in Southeast New Mexico. These activities could result in delays in the production of our proved reserves from the Paddock interval in the event that commingling of both formations is imprudent or otherwise not feasible.

Part of our strategy involves exploratory drilling, including drilling in new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

 

The results of our exploratory drilling in new or emerging areas are more uncertain than drilling results in areas that are developed and have established production. Since new or emerging plays and new formations have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

 

Our commodity price risk management program may cause us to forego additional future profits or result in our making cash payments to our counterparties.

 

To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Commodity price risk management arrangements expose us to the risk of financial loss and may limit our ability to benefit from increases in oil and natural gas prices in some circumstances, including the following:

 

 

Our commodity price risk management activities could have the effect of reducing our revenues, net income and the value of our common stock. As of December 31, 2007, the net unrealized loss on our commodity price risk management contracts was approximately $45.1 million. An average increase in the commodity price of $1.00 per barrel of crude oil and $0.10 per Mcf for natural gas from the commodity prices as of December 31, 2007 would have resulted in an increase in the net unrealized loss on our commodity price risk management contracts, as reflected on our balance sheet as of December 31, 2007, of approximately $2.7 million. We may continue to incur significant unrealized losses in the future from our commodity price risk management activities to the extent market prices continue to increase and our derivatives contracts remain in place. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Commodity Derivatives and Hedging.”

 

If we enter into derivative instruments that require us to post cash collateral, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures.

 

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures. Future collateral requirements will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

 

Our business requires substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves.

 

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the acquisition, exploration and development of oil and natural gas reserves. For example, during the first three months of 2007, we curtailed our drilling program in order to preserve liquidity

until we could complete our second lien term loan facility. As of December 31, 2007, our total debt outstanding was $327.4 million, and $209.0 million was available to be borrowed under our revolving credit facility. Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. We invested approximately $183 million in 2007 and anticipate investing approximately $250 million in 2008 for acquisition, exploration and development activities on our properties. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Capital Expenditures and Commitments.”

 

We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of outstanding common stock. Additional borrowings under our revolving credit facility or the issuance of additional debt will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. In addition, our bank credit facilities impose certain limitations on our ability to incur additional indebtedness other than indebtedness under our revolving credit facility. If we desire to issue additional debt securities other than as expressly permitted under our bank credit facilities, we will be required to seek the consent of the lenders in accordance with the requirements of those facilities, which consent may be withheld by the lenders under our bank credit facilities in their discretion. Additional financing also may not be available on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

 

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

 

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. As a result, we may require additional capital to fund our operations, and we may not be able to obtain debt or equity financing to satisfy our capital requirements. If cash generated from operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition or results of operations.

 

Our identified inventory of drilling locations and recompletion opportunities are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

Our management has specifically identified and scheduled the drilling and recompletion of our drilling and recompletion opportunities as an estimation of our future multi-year development activities on our existing acreage. As of December 31, 2007, we had identified 1,659 drilling locations with proved undeveloped reserves attributable to 627 of such locations, and 878 recompletion opportunities with proved undeveloped reserves attributed to 375 of such opportunities. These identified opportunities represent a significant part of our growth strategy. Our ability to drill and develop these opportunities depends on a number of uncertainties, including the availability of capital, equipment, services and personnel, seasonal conditions, regulatory and third party approvals, oil and natural gas prices, costs and drilling and recompletion results. Because of these uncertainties, we may never drill or recomplete the numerous potential opportunities we have identified or produce oil or natural gas from these or any other

potential opportunities. As such, our actual development activities may materially differ from those presently identified, which could adversely affect our business.

 

Approximately 46% of our total estimated net proved reserves as of December 31, 2007, were undeveloped, and those reserves may not ultimately be developed.

 

As of December 31, 2007, approximately 46% of our total estimated net proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves, or if we are not able to successfully develop these reserves, we will be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our common stock.

 

Because we do not control the development of the properties in which we own interests, but do not operate, we may not be able to achieve any production from these properties in a timely manner.

 

As of December 31, 2007, approximately 10% of our PV-10 was attributable to properties for which we were not the operator. As a result, the success and timing of drilling and development activities on such nonoperated properties depend upon a number of factors, including:

 

 

If drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, which may adversely affect our production, revenues and results of operations.

 

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flow, our ability to raise capital and the value of our common stock.

 

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. The value of our common stock and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.

 

We may be unable to make attractive acquisitions or integrate acquired companies, and any inability to do so may disrupt our business and hinder our ability to grow through the acquisition of businesses.

 

One aspect of our business strategy calls for acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities.

 

Even if we do identify attractive candidates, we may not be able to complete the acquisition of them or do so on commercially acceptable terms.

 

In addition, our bank credit facilities impose certain direct limitations on our ability to enter into mergers or combination transactions involving our company. Our bank credit facilities also limit our ability to incur certain

indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses. If we desire to engage in an acquisition that is otherwise prohibited by our bank credit facilities, we will be required to seek the consent of the lenders in accordance with the requirements of those facilities, which consent may be withheld by the lenders under our bank credit facilities in their discretion.

 

If we acquire another business, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own. These difficulties could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations. In addition, we may incur additional debt or issue additional equity to pay for any future acquisitions, subject to the limitations described above.

 

Properties acquired may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

 

We obtained the majority of our current reserve base through acquisitions of producing properties and undeveloped acreage. We expect acquisitions will continue to contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and we cannot make these assessments with a high degree of accuracy. In connection with our assessments, we perform a review of the acquired properties. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.

 

We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties.

 

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

 

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, those companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. Our failure to acquire properties, market oil and natural gas and secure trained personnel and increased compensation for trained personnel could have a material adverse effect on our business.

 

Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.

 

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment,

services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted or which we may plan in the future.

 

Our exploration and development drilling may not result in commercially productive reserves.

 

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. New wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

 

 

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

 

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

 

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company as a result of:

 

 

 

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 fully insurable. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our business, financial condition or results of operations.

 

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

 

Market conditions or the unavailability of satisfactory oil and natural gas processing or transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could have a material adverse effect on our business, financial condition and results of operations. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipeline or gathering system or processing capacity. If that were to occur, then we would be unable to realize revenue from those wells until suitable arrangements were made to market our production.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, timing, manner or feasibility of conducting our operations.

 

Our oil and natural gas exploration, development and production, and saltwater disposal operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. We may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase or our operations may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For instance, the New Mexico Oil Conservation Division is considering amending or replacing an existing rule regulating the permitting, construction, operation and closure of oilfield pits at well sites in New Mexico. If the agency adopts a new or revised pit rule that imposes stricter requirements on the construction and use of oilfield pits, then it is possible that the cost to operate our wells in New Mexico could increase. These and other future costs could have a material adverse effect on our business, financial condition or results of operations.

 

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition or results of operations. See “Item 1. Business — Applicable Laws and Regulations” for a description of certain laws and regulations that affect us.

 

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

 

We may incur significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and natural gas exploration, development and production, and saltwater disposal activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment, health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time. Failure to comply with these laws and regulations

may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.

 

Strict as well as joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected. See “Item 1. Business — Applicable Laws and Regulations — Environmental, Health and Safety Matters” for more information.

 

The loss of our chief executive officer or our chief operating officer or other key personnel could negatively impact our ability to execute our business strategy.

 

We depend, and will continue to depend in the foreseeable future, on the services of Timothy A. Leach, our chairman of the board and chief executive officer, Steven L. Beal, our president and chief operating officer, our other executive officers and our key employees who have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and gas production, and developing and executing acquisition, financing and hedging strategies. Our ability to hire and retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could negatively impact our ability to execute our business strategy.

 

Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on the investments we make to use such methods.

 

We inject water into formations on some of our properties to increase the production of oil and natural gas. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in our operations. The additional production and reserves attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate, we may not realize an acceptable return on the investments we make to use such methods.

 

Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

 

We now have, and will continue to have, a significant amount of indebtedness, and the terms of our revolving credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base. As of December 31, 2007, our total debt was $327.4 million. At December 31, 2007, our revolving credit facility bore interest at a rate of 6.16% per annum and our second lien term loan facility bore interest at 9.23% per annum. Assuming our total debt outstanding as of December 31, 2007 was held constant throughout the year, if interest rates had been higher or lower by 1% per annum, interest expense for the year ended December 31, 2007 would have increased or decreased by approximately $3.3 million. As of December 31, 2007, our total borrowing capacity under our revolving credit facility was $425.0 million, of which $209.0 million was available.

 

Our current and future indebtedness could have important consequences to you. For example, it could:

 

 

 

Our ability to meet our debt service and other obligations may depend in significant part on the extent to which we can successfully implement our business strategy. We may not be able to implement or realize the benefits of our business strategy.

 

Our existing bank credit facilities impose restrictions on us that may affect our ability to successfully operate our business.

 

Our bank credit facilities limit our ability to take various actions, such as:

 

 

In addition, our bank credit facilities require us to maintain certain financial ratios and to satisfy certain financial conditions, which may require us to reduce our debt or take some other action in order to comply with each of them.

 

These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under each of our bank credit facilities.

 

A terrorist attack or armed conflict could harm our business by decreasing our revenues and increasing our costs.

 

Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities we use for the production, transportation or marketing of our oil and natural gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

 

Our certificate of incorporation, bylaws and Delaware law contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

 

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

 

Because we have no plans to pay dividends on our common stock, stockholders must look solely to stock appreciation for a return on their investment in us.

 

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. The terms of our existing bank credit facilities restrict the payment of dividends without the prior written consent of the lenders. Stockholders must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.

 

The availability of shares for sale in the future could reduce the market price of our common stock.

 

In the future, we may issue securities to raise cash for acquisitions, the payment of our indebtedness or other purposes. We may also acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We may also issue securities convertible into our common stock. Any of these events may dilute your ownership interest in our company and have an adverse impact on the price of our common stock.

 

In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.

 

Developed and Undeveloped Acreage

 

The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2007:

 

 

 

 

 

The following table sets forth the amount of our gross and net undeveloped acreage as of December 31, 2007 that will expire over the next three years by region except where production is established within applicable spacing units on such acreage prior to applicable expiration dates:

 

 

 

 

The following table sets forth our estimated net proved oil and natural gas reserves, PV-10 and standardized measure of discounted future net cash flows as of December 31, 2007. PV-10 includes the present value of our estimated future abandonment and site restoration costs for proved properties net of the present value of estimated salvage proceeds from each of these properties. Our reserve estimates are based on independent engineering evaluations prepared by Netherland, Sewell & Associates, Inc. and Cawley Gillespie & Associates, Inc. as of December 31, 2007 ($92.50 per Bbl Plains Marketing, L.P. West Texas Intermediate posted oil price and $6.795 per MMBtu NYMEX Henry Hub spot natural gas price, adjusted for location and quality by field, were used in the computation of future net cash flows).

 

 

 

 

 

The following table sets forth our estimated net proved reserves and PV-10 as of December 31, 2007, by region:

 

 

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect defects affecting those properties, we are typically responsible for curing any such defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have reviewed the title to substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review or update previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our bank credit facilities, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.

 

 

PART II

 

Equity Compensation Plans

 

At December 31, 2007, a total of 5,850,000 shares of common stock were authorized for issuance under our equity compensation plan. In the table below, we describe certain information about these shares and the equity compensation plan which provides for their authorization and issuance. You can find a description of our stock incentive plan under Note H — Stock incentive plan in the notes to the consolidated financial statements.

 

 

 

 

This section presents our selected historical consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included in this annual report.

 

The following table shows selected historical financial data related to Concho (as the accounting successor to Concho Equity Holdings Corp., which is now known as Concho Equity Holdings LLC) and combined financial data of the Chase Group Properties. We have accounted for the combination transaction that occurred on February 27, 2006, as an acquisition by Concho Equity Holdings Corp. of the Chase Group Properties and a simultaneous reorganization of Concho such that Concho Equity Holdings Corp. is now our wholly owned subsidiary.

 

Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward, for the following reasons:

 

 

The historical financial data for the Chase Group Properties for the years ended December 31, 2005, 2004 and 2003 are derived from the audited financial statements of the Chase Group Properties included in our prospectus dated August 2, 2007 and filed with the SEC pursuant to Rule 424(b) on August 3, 2007. The historical financial data for Concho for the years ended December 31, 2007, 2006 and 2005, and for the period from inception (April 21, 2004) through December 31, 2004, are derived from the audited financial statements of Concho.