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(b) of the Act:

 

 

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

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.  Yes þ     No o

 

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.  þ

 

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

 

 

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

 

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter:

$1,993,092,788

 

Number of shares of registrant’s common stock outstanding as of February 19, 2009:                          84,913,298

 

Documents Incorporated by Reference:

 

Portions of the registrant’s definitive proxy statement for its 2009 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2008, are incorporated by reference into Part III of this report for the year ended December 31, 2008.

 

 

Table of Contents

 

 

This report may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) 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 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 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 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:

 

 

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

 

The following terms are used throughout this report:

 

 

 

 

 

Concho Resources Inc., a Delaware corporation (“Concho,” “Company,” “we,” “us” and “our”) is an independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of oil and natural gas properties. Our core operations are focused in the Permian Basin of Southeastern New Mexico and West Texas. These core operating areas are complemented by our activities in our emerging plays. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year project inventory and through acquisitions that meet our strategic and financial objectives.

 

We were formed in February 2006 as a result of the combination of Concho Equity Holdings Corp. and a portion of the oil and natural gas properties and related assets owned by Chase Oil Corporation (“Chase Oil”) and certain of its affiliates. Concho Equity Holdings Corp. was formed in April 2004 and represented the third of three Permian Basin-focused companies that have been formed since 1997 by certain members of our current management team (the prior two companies were sold to large domestic independent oil and gas companies).

 

On July 31, 2008, we closed our acquisition of Henry Petroleum LP and certain entities affiliated with Henry Petroleum LP (which we refer to collectively as the “Henry Entities”), together with certain additional non-operated interests in oil and gas properties from persons affiliated with the Henry Entities. In August 2008 and September 2008, we acquired additional non-operated interests in oil and gas properties from persons affiliated with the Henry Entities. We paid approximately $584.1 million in net cash for the acquisition of the Henry Entities and the related acquisition of the along-side interests, which was funded with (i) borrowings under our credit facility and (ii) net proceeds of approximately $242.4 million from our private placement of 8,302,894 shares of our common stock. The oil and gas assets acquired in the acquisition of the Henry Entities and the along-side interests (which we refer to as the “Henry Properties”) contained approximately 30.1 MMBoe of net proved reserves at the acquisition date.

 

On February 24, 2006, we entered into a combination agreement in which we agreed to purchase oil and gas properties owned by Chase Oil, Caza Energy LLC and other related 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 then received 34,683,315 shares of our common stock and approximately $400 million in cash. The oil and gas properties contributed to us by the Chase Group are referred to as the “Chase Group Properties.”

 

Our core operations are focused in the Permian Basin of Southeastern New Mexico and West Texas. The Permian Basin is one of the most prolific producing oil and gas regions in the United States. It underlies an area of Southeastern 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 basin is characterized by long life, shallow decline reserves. At December 31, 2008, 97.9 percent of our total estimated net proved reserves were located in our core operating areas and consisted of approximately 62.9 percent crude oil and 37.1 percent natural gas. We refer to our core operating areas as (i) New Mexico Permian and (ii) Texas Permian. The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators. Producing horizons in our core properties include (i) the Yeso in the New Mexico Permian, which is located at depths ranging from 3,800 feet to 7,500 feet and (ii) the Wolfberry in the Texas Permian, the term applied to the combined Wolfcamp and Spraberry horizons, which is located at depths ranging from 7,000 feet to

10,500 feet. We have assembled a multi-year inventory of development drilling and exploitation projects, including projects to further evaluate the aerial extent of the Yeso formation and the Wolfberry play, that we believe will allow us to grow proved reserves and production. We also have significant acreage positions in active emerging plays in the Lower Abo horizontal play in Southeastern New Mexico and the Bakken/Three Forks play in North Dakota. We view an emerging play as an area where we can acquire large undeveloped acreage positions and apply horizontal drilling, advanced fracture stimulation and/or enhanced recovery technologies to achieve economic and repeatable production results.

 

In 2008, we drilled or participated in the drilling of 243 gross (157.2 net) wells, 86.8 percent of which were completed as producers, 0.4 percent of which were dry holes and 12.8 percent of which were awaiting completion at December 31, 2008. In addition, in 2008, we recompleted or participated in the recompletion of 242 gross (198.6 net) wells, 90.9 percent of which were productive, 2.1 percent of which were unsuccessful and 7 percent were still in progress at December 31, 2008. We increased our total estimated net proved reserves by approximately 53.4 MMBoe, taking into account the effects of negative price revisions (10.1 MMBoe) and acquisitions. We produced approximately 7.1 MMBoe of oil and natural gas during 2008. In addition, we increased our average net daily production from 15.6 MBoe during the first quarter of 2008 to 25.2 MBoe during the fourth quarter of 2008, including the impact of the acquisition of the Henry Properties.

 

The following table sets forth information with respect to wells drilled and completed during the periods indicated. The 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.

 

 

The following table sets forth information about our wells for which drilling was in progress or are pending completion at December 31, 2008, which are not included in the above table:

 

 

The following table sets forth summary information concerning our production results, average sales prices and operating costs and expenses for the years ended December 31, 2008, 2007 and 2006. The actual historical data in this table excludes production from the (i) Chase Group Properties for periods prior to February 27, 2006 and (ii) Henry Properties for periods prior to August 1, 2008.

 

 

The following is a summary of information regarding our core operating areas and emerging plays that are further described below:

 

 

Core Operating Areas

 

Our core operating areas are located in the Permian Basin region of Southeastern New Mexico and West Texas, the largest onshore oil and gas basin in the United States. We refer to our core operating areas as the (i) New Mexico Permian and (ii) Texas Permian. At December 31, 2008, our core operating areas had estimated net proved reserves

of 134.4 MMBoe, which accounted for 97.9 percent of our total estimated net proved reserves and 97.4 percent of our PV-10. At December 31, 2008, we owned interests in 3,403 gross wells in our core operating areas, of which we operated 2,294 (gross). At December 31, 2008, in our core operating areas, we had identified 3,465 drilling locations, with proved undeveloped reserves attributed to 811 of such locations, and 2,118 recompletion opportunities, with proved reserves attributed to 916 of such opportunities.

 

New Mexico Permian.  We acquired the majority of our properties in this area from the Chase Group. This area represents our most significant concentration of assets and, at December 31, 2008, our estimated proved reserves of 95.1 MMBoe in this area accounted for 69.2 percent of our total net proved reserves and 75.1 percent of our PV-10. During 2008, our average net daily production from this area was approximately 14.7 MBoe per day, representing 75.6 percent of our total production for that time period.

 

Within this area we target two distinct producing areas, which we refer to 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 Strawn, Atoka and Morrow formations, with producing depths generally ranging from 7,500 feet to 15,000 feet.

 

During 2008, we drilled or participated in the drilling of 142 (123.9 net) wells in this area, of which 132 (114.4 net) were completed as producers, none were unsuccessful and 10 (9.5 net) were awaiting completion at December 31, 2008. During 2008, we (i) continued our development of the Blinebry interval of the Yeso formation, the top of which is located approximately 400 feet below the top of the Paddock interval of the Yeso formation, (ii) began our evaluation of drilling on 10 acre spacing in the Blinebry interval and (iii) continued our evaluation of the use of larger fracture stimulation procedures in the completion of certain wells. In addition, we continued our pilot waterflood commenced in September 2007 injecting water into the Paddock interval.

 

At December 31, 2008, we had 153,425 gross (71,423 net) acres in this area. At December 31, 2008, on our properties in this area, we had identified 1,685 drilling locations, with proved undeveloped reserves attributed to 355 of such locations, and 1,908 recompletion opportunities, with proved reserves attributed to 720 of such opportunities. Of the drilling locations we identified 993 locations intended to evaluate both the Blinebry and the Paddock intervals, while 17 locations are intended to evaluate only the Blinebry interval, with proved undeveloped reserves attributed to 176 of such total drilling locations.

 

Texas Permian.  We acquired the majority of our properties in this area in the Henry Properties acquisition. At December 31, 2008, our estimated proved reserves of 39.4 MMBoe in this area accounted for 28.7 percent of our total net proved reserves and 22.3 percent of our PV-10. During 2008, our average net daily production from this area was approximately 4.0 MBoe per day, representing 20.7 percent of our total production for that time period.

 

The primary objective in the Texas Permian area is the Wolfberry in the Midland Basin. Wolfberry is the term applied to the combined Spraberry and Wolfcamp target interval which is typically encountered at depths of 7,000 to 10,500 feet. The Wolfberry is comprised of a sequence of basinal, interbedded shales and carbonates. We also operate properties on the Central Basin Platform where the Grayburg, San Andres and Clearfork objectives are shallower, typically encountered at depths of 4,500 to 7,500 feet. The reservoirs in these formations are largely carbonates, limestones and dolomites.

 

At December 31, 2008, we had 241,508 gross (69,727 net) acres in this area. In addition, at December 31, 2008, we had identified 1,780 drilling locations, with proved undeveloped reserves attributed to 456 of such locations, and 210 recompletion opportunities, with proved reserves attributed to 196 of such opportunities.

 

During 2008, we drilled or participated in the drilling of 69 (24.9 net) wells in this area, of which 54 (20.1 net) were completed as producers, none were unsuccessful and 15 (4.8 net) wells were awaiting completion at December 31, 2008. In addition, during 2008, we commenced the recompletion of 26 wells, 25 of which were producing at December 31, 2008 and 1 of which was unsuccessful.

Emerging Plays

 

At December 31, 2008, we were actively involved in drilling or participating in drilling activities in two emerging plays, in which we held 68,337 gross (32,861 net) acres and 2.3 MMBoe of proved reserves.

 

Lower Abo horizontal play.  The Lower Abo horizontal play is an oil play along the northwestern rim of the Delaware Basin in Lea, Eddy and Chaves Counties, New Mexico. This play is found at vertical depths ranging from 6,500 feet to 9,000 feet and is being exploited utilizing horizontal drilling techniques.

 

At December 31, 2008, we held interests in 25,535 gross (21,638 net) acres in this play. In 2008, we drilled or participated in the drilling of 11 wells in this play with 8 wells producing, 1 waiting on completion and 2 wells drilling at December 31, 2008. At December 31, 2008, we had 2.1 MMBoe of proved reserves in the play.

 

Bakken/Three Forks play.  The Bakken/Three Forks play is in the Williston Basin in North Dakota, primarily in Mountrail and McKenzie Counties. This Mississippian/Devonian age horizon consists of siltstones encased within and below a highly organic oil-rich shale package. This horizon is found at vertical depths ranging from 9,000 feet to 11,000 feet and is being exploited utilizing horizontal drilling techniques.

 

At December 31, 2008, we held interests in 42,802 gross (11,223 net) acres in this play. In 2008, we participated in the drilling of 17 wells in this play with 14 wells producing, 2 waiting on completion and 1 well drilling at December 31, 2008. At December 31, 2008, we had 0.2 MMBoe of proved reserves in the play.

 

Other emerging plays.  We also own interests in the following other emerging plays:

 

 

Because of the current commodity price environment, the minimal success from drilling in these three other emerging plays and other activity in or around these three other emerging plays, we are currently not actively pursuing further exploration activities on these three other emerging plays. We are evaluating our alternatives related to these three other emerging plays.

 

General.  We market our crude oil and natural gas in accordance with standard energy practices utilizing certain of our employees and external 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 drilling 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. A significant portion of our crude oil is connected directly to pipelines via gathering facilities in the respective field locations throughout Southeastern New Mexico, while a significant portion of our production in West Texas is transported by truck. The oil is then delivered either to hub facilities located in Midland, Texas or Cushing, Oklahoma or to third party refineries located in Southeastern New Mexico and the Panhandle and Gulf Coast area of Texas, with the majority of our crude oil going to a refinery in Southeastern New Mexico. 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.  We consider all 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 sold at the lease 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 a percentage of 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 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 2008, revenues from oil and natural gas sales to Navajo Refining Company, L.P. and DCP Midstream, LP accounted for approximately 59 percent and approximately 18 percent, 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 caused significant price increases. The recent 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 timing or duration of any such shortages.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights. 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 the Oil and Natural Gas Industry

 

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 cost-based, 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 permits a pipeline, subject to limited challenges, to annually increase or decrease its transportation rates due to inflationary changes in costs using a FERC approved index. On March 21, 2006, FERC issued a decision setting the index for the period July 1, 2006 through July 2011 at the Producer Price Index for Finished Goods (PPI-FG) plus 1.3 percent. 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 at posted tariff 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, and market participants are prohibited from engaging in market manipulation. 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 these 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.

In August, 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act up to $1 million per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. EPAct 2005 therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.

 

In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as Concho, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus during a calendar year to annually report, starting May 1, 2009, such sales and purchases to the FERC. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. We do not anticipate that we will be affected by these rules any differently than other producers of natural gas.

 

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. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. 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.

 

Environmental, Health and Safety Matters

 

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 is subject.

 

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.

 

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases. President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. This requirement could increase our operational and compliance costs and result in reduced demand for our products.

 

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate 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 Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal 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. In July 2008, the EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, the EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state

restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on our business and the 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, 2008. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2009. However, we cannot assure you that the passage or application of more stringent laws or regulations in the future will not have an negative impact on our financial position or results of operation.

 

At December 31, 2008, we employed 245 persons, including 128 in operations, 33 in financial and accounting, 33 in land, 16 in geosciences, 17 in reservoir engineering and 18 in administration. Of these, 220 worked at our Midland, Texas headquarters, including Texas field operations, and 25 in our New Mexico 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 SEC under the Exchange Act. The public may read and copy any materials that we file with 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 us, 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.

 

You should consider carefully the following risk factors together with all of the other information included in this report and other reports filed with the SEC, before investing in our shares. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our shares could decline and you could lose all or part of your investment.

 

Crude oil and natural gas prices are volatile. A decline in crude oil and natural gas prices could adversely affect our financial position, financial results, cash flow, access to capital and ability to grow.

 

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and gas properties depend primarily upon the prices we receive for our crude oil and natural gas production and the prices prevailing from time to time for crude oil and natural gas. Crude oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the amount of our cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices for crude oil and natural gas are subject to a variety of factors, including:

 

 

Furthermore, crude oil and natural gas prices were particularly volatile in 2008. For example, the NYMEX crude oil prices in 2008 ranged from a high of $145.29 to a low of $33.87 per Bbl, and the NYMEX natural gas prices in 2008 ranged from a high of $13.58 to a low of $4.35 per MMBtu. Further demonstrating the volatility of crude oil and natural gas prices, the NYMEX crude oil prices and NYMEX natural gas prices reached lows of $33.98 per Bbl and $4.08 per MMBtu, respectively, during the period from January 1, 2009 to February 19, 2009.

 

Further declines in crude oil and natural gas prices would not only reduce our revenue, but could further reduce the amount of crude 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 gas industry continues to experience 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 adversely affect the value of our common stock.

Drilling for and producing crude 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 crude oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable crude 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. 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 or less economic than forecasted. Further, many factors may curtail, delay or cancel drilling, including the following:

 

 

Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and our future net cash flows may prove to be lower than estimated.

 

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Our estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate.

 

Petroleum engineering is a subjective process of estimating accumulations of crude oil and/or natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

 

 

Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:

 

 

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

 

As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. For example, the estimated discounted future net cash flows from our proved reserves at December 31, 2008 were calculated using the West Texas Intermediate posted crude oil price of $41.00 per Bbl and the NYMEX natural gas price of $5.71 per MMBtu, adjusted for location and quality by field, while the actual future net cash flows also will be affected by other factors, including:

 

 

Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. It requires the use of commodity prices, as well as operating and development costs, prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for crude oil and natural gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows or Standardized Measure included herein should not be construed as accurate estimates of the current market value of our proved reserves. If oil prices were $1.00 per Bbl lower than the price we used, our PV-10 at December 31, 2008, would have decreased from $1,663 million to $1,622 million. If natural gas prices were $0.10 per Mcf lower than the price we used, our PV-10 at December 31, 2008, would have decreased from $1,663 million to $1,646 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.

 

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 crude oil and natural gas reserves.

 

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition, exploration and development of crude oil and natural gas reserves. At December 31, 2008, total debt outstanding under our credit facility was $630.0 million, and $329.7 million was available to be borrowed. Expenditures for exploration and development of oil and gas properties are the primary use of our capital resources. We invested approximately $339.0 million in exploration and development activities in 2008, and anticipate we could invest up to approximately $500 million in 2009 for exploration and development activities, dependent on our cash flow, on our properties under our original capital budget.

We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our 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 our outstanding common stock. Additional borrowings under our 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 credit facility imposes certain limitations on our ability to incur additional indebtedness other than indebtedness under our credit facility. If we desire to issue additional debt securities other than as expressly permitted under our credit facility, we will be required to seek the consent of the lenders in accordance with the requirements of the facility, which consent may be withheld by the lenders under our credit facility 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 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 production, revenues and results of operations.

 

We may not be able to obtain funding at all, or obtain funding on acceptable terms, to meet our future capital needs because of the deterioration of the credit and capital markets.

 

Global financial markets and economic conditions have been, and will likely continue to be, disrupted and volatile. The debt and equity capital markets have become uncertain. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

 

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. Also, as a result of concern about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards and reduced and, in some cases, ceased to provide funding to borrowers.

 

In addition, our ability to obtain capital under our credit facility may be impaired because of the recent downturn in the financial market, including the issues surrounding the solvency of certain institutional lenders and the recent failure of several banks. Specifically, we may be unable to obtain adequate funding under our credit facility because:

 

 

 

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

 

Our lenders can limit our borrowing capabilities, which may materially impact our operations.

 

At December 31, 2008, we had approximately $630 million of outstanding debt under our credit facility, and our borrowing base was $960 million. The borrowing base limitation under our credit facility is semi-annually redetermined based upon a number of factors, including commodity prices and reserve levels. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any twelve-month period. Upon a redetermination, our borrowing base could be substantially reduced, and in the event the amount outstanding under our credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. We utilize cash flow from operations, bank borrowings and equity financings to fund our acquisition, exploration and development activities. A reduction in our borrowing base could limit our activities. In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.

 

Our producing properties are located in the Permian Basin of Southeastern New Mexico and West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

 

Our producing properties in our core operating areas are geographically concentrated in the Permian Basin of Southeastern New Mexico and West Texas. At December 31, 2008, 97.4 percent of our PV-10 was attributable to properties located in our core operating areas. 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 wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids.

 

In addition to the geographic concentration of our producing properties described above, at December 31, 2008, approximately (i) 52.0 percent of our proved reserves were attributable to the Yeso formation, which includes both the Paddock and Blinebry intervals, underlying our oil and gas properties located in Southeastern New Mexico; and (ii) 15.1 percent of our proved reserves were attributable to the Wolfberry play in West Texas. This concentration of assets within a small number of producing horizons exposes us to additional 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 a field.

 

Future price declines could result in a reduction in the carrying value of our proved oil and gas properties, which could adversely affect our results of operations.

 

Declines in commodity prices may result in having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of production or economic factors change, accounting rules may require us to write-down, as a noncash charge to earnings, the carrying value of our oil and gas properties for impairments. We are required to perform impairment tests on proved assets whenever events or changes in circumstances warrant a review of our proved oil and gas properties. To the extent such tests indicate a reduction of

the estimated useful life or estimated future cash flows of our oil and gas properties, the carrying value may not be recoverable and therefore require a write-down. We may incur impairment charges in the future, which could materially adversely affect our results of operations in the period incurred.

 

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 crude 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 crude 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 crude 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 crude 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. At December 31, 2008, the net unrealized gain on our commodity price risk management contracts was approximately $172.4 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 at December 31, 2008 would have resulted in a decrease in the net unrealized gain on our commodity price risk management contracts, as reflected on our balance sheet at December 31, 2008, of approximately $3.6 million. We may continue to incur significant unrealized gains or losses in the future from our commodity price risk management activities to the extent market prices increase or decrease and our derivatives contracts remain in place.

 

We have entered into interest rate derivative instruments that may subject us to loss of income.

 

We have entered into derivative instruments designed to limit the interest rate risk under our current credit facility or any credit facilities we may enter into in the future. These derivative instruments can involve the exchange of a portion of our floating rate interest obligations for fixed rate interest obligations or a cap on our exposure to floating interest rates to reduce our exposure to the volatility of interest rates. While we may enter into instruments limiting our exposure to higher market interest rates, we cannot assure you that any interest rate derivative instruments we implement will be effective; and furthermore, even if effective these instruments may not offer complete protection from the risk of higher interest rates.

 

All interest rate derivative instruments involve certain additional risks, such as:

 

 

 

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 or interest rates 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 crude oil and natural gas prices and interest rates.

 

Nonperformance by the counterparties to our derivative instruments and commodity purchase agreements could adversely affect our financial condition and results of operations.

 

We routinely enter into derivative instruments with a number of counterparties to reduce our exposure to changes in oil and natural gas prices and interest rates. Recently, a number of financial institutions similar to those that serve as counterparties to our derivative instruments have been adversely affected by the global credit crisis. If a counterparty to one of these derivative instruments cannot or will not perform under the contract, we will not realize the benefit of the derivative, which could adversely affect our financial condition and results of operations.

 

Additionally, substantially all of our accounts receivable result from oil and natural gas sales to third parties in the energy industry. Recent market conditions have resulted in downgrades to credit ratings of energy industry merchants and financial institutions, affecting the liquidity of several of our purchasers and counterparties. We extend credit to our purchasers based on each party’s creditworthiness, but we generally have not required our purchasers to provide collateral support for their obligations to us and therefore have no assurances that our counterparties will have the ability to pay us. If a purchaser of our oil and natural gas production fails to meet its obligations under our commodity purchase agreement, our financial condition and results of operations could be adversely affected.

 

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.

 

We have 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. At December 31, 2008, we had identified 3,589 drilling locations with proved undeveloped reserves attributable to 823 of such locations, and 2,121 recompletion opportunities with proved undeveloped reserves attributed to 540 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 (i) our ability to timely drill wells on lands subject to complex development terms and circumstances; and (ii) the availability of capital, equipment, services and personnel, seasonal conditions, regulatory and third party approvals, crude oil and natural gas prices, and drilling and recompletion costs and results. Because of these uncertainties, we may never drill or recomplete the numerous potential opportunities we have identified or produce crude 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 production, revenues and results of operations.

 

Approximately 44.3 percent of our total estimated net proved reserves at December 31, 2008, were undeveloped, and those reserves may not ultimately be developed.

 

At December 31, 2008, approximately 44.3 percent 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.

 

At December 31, 2008, approximately 6.7 percent 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 crude 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 crude oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude 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 successfully integrate acquired companies, and any inability to do so may disrupt our business and hinder our ability to grow.

 

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 credit facility imposes certain direct limitations on our ability to enter into mergers or combination transactions involving our company. Our credit facility also limits 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 credit facility, we will be required to seek the consent of our lenders in accordance with the requirements of the facility, which consent may be withheld by the lenders under our credit facility in their discretion. Furthermore, given the current situation in the credit markets, many lenders are reluctant to provide consents in any circumstances, including to allow accretive transactions.

 

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.

 

The acquisition of the Henry Entities could expose us to potentially significant liabilities.

 

In connection with the acquisition of the Henry Entities, we purchased all of the sellers’ interests in the Henry Entities, rather than individual assets; therefore, the Henry Entities retained their liabilities, subject to certain exclusions and limitations contained in the purchase agreement, including certain unknown and contingent liabilities. We performed limited due diligence in connection with the acquisition of the Henry Entities and attempted to verify the representations of the sellers and of the former management of the Henry Entities, but there may be threatened, contemplated, asserted or other claims against the Henry Entities related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially adversely affect our production, revenues and results of operations. In addition, although the sellers agreed to indemnify us on a limited basis against certain liabilities, these indemnification obligations will expire over time and expose us to potential unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations.

 

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, including those owned by the Henry Entities. We expect that acquisitions will continue to contribute to our future growth. Successful acquisitions of oil and gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future crude oil and natural 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 sometimes unable to obtain contractual indemnification for preclosing liabilities, including environmental liabilities and often acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties.

 

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

 

We operate in a highly competitive environment for acquiring properties, marketing crude 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 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 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 crude oil and natural gas and secure trained personnel and adequately compensate personnel could have a material adverse effect on our production, revenues and results of operations.

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 gas industry can fluctuate significantly, often in correlation with crude oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe 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 crude oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover 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 crude oil or natural gas is present or may be produced economically. Drilling for crude 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 periodically evaluate our unproved oil and gas properties for impairment, and could be required to recognize noncash charges to earnings of future periods.

 

At December 31, 2008, we carried unproved property costs of $377.2 million. GAAP requires periodic evaluation of these costs on a project-by-project basis in comparison to their estimated fair value. These evaluations will be affected by the results of exploration activities, commodity price circumstances, planned future sales or expiration of all or a portion of the leases, contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, we will recognize noncash charges to earnings of future periods.

 

We may incur substantial losses and be subject to substantial liability claims as a result of our crude 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 crude oil and

natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude 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 us 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 production, revenues and results of operations.

 

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

 

Market conditions or the unavailability of satisfactory crude oil and natural gas processing or transportation arrangements may hinder our access to crude oil and natural gas markets or delay our production. The availability of a ready market for our crude oil and natural gas production depends on a number of factors, including the demand for and supply of crude oil and natural gas, the proximity of reserves to pipelines and terminal facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from mechanical, operational or weather related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering and transportation 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, natural gas liquids or natural gas pipeline or gathering, transportation 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 crude 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. These and other costs could have a material adverse effect on our production, revenues and 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, crude oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our production, revenues and results of operations.

 

We may incur substantial costs to comply with, and demand for our products may be reduced by, climate change legislation and regulatory initiatives.

 

The United States Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. In addition, the EPA has announced possible future regulation of greenhouse gas emissions under the Clean Air Act. Depending on the nature of potential regulations and legislation, such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for the oil and natural gas we produce.

 

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 crude 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 production, revenues and results of operations could be adversely affected.

 

The loss of our chief executive 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 our chief executive officer, Timothy A. Leach, and other key employees who have extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and 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 our investments in such projects.

 

We inject water into formations on some of our properties to increase the production of crude 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, if any, 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 crude oil and natural gas in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects.

 

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 credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base. At December 31, 2008, our total debt was $630.0 million. Assuming our total debt outstanding at December 31, 2008 was held constant, if interest rates had been higher or lower by 1 percent per annum, our annual interest expense would have increased or decreased by approximately $6.3 million. At December 31, 2008, our total borrowing capacity under our credit facility was $960 million, of which $329.7 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 credit facility imposes restrictions on us that may affect our ability to successfully operate our business.

 

Our credit facility limits our ability to take various actions, such as:

 

 

In addition, our credit facility requires 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 our credit facility.

 

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 crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Crude 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 crude 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 restated certificate of incorporation, amended and restated 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 restated 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 restated certificate of incorporation, amended and restated 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 credit facility restricts 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 solely our common stock. We may also issue securities convertible into our common stock. Any of these events may dilute your ownership interest in us 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.

 

 

There are no unresolved staff comments.

 

 

The following table sets forth our estimated net proved oil and natural gas reserves, PV-10 and Standardized Measure at December 31, 2008. 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. at December 31, 2008 ($41.00 per Bbl West Texas Intermediate posted oil price and $5.71 per MMBtu NYMEX 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 certain proved reserve information by region at December 31, 2008:

 

 

 

 

The following table sets forth our estimated net proved reserves by category at December 31, 2008:

 

 

The following table sets forth the estimated timing and cash flows of developing our proved undeveloped reserves at December 31, 2008 (dollars in thousands):

 

 

 

 

The following table sets forth the changes in our proved reserve volumes by region during the year ended December 31, 2008 (in MBoe):

 

 

Production.  Production volumes of 7.1 MMBoe includes production from our acquisition of the Henry Properties since August 1, 2008.

 

Extensions and discoveries.  Extensions and discoveries are primarily the result of extension drilling in the Yeso formation of Southeastern New Mexico and the Wolfberry formation in West Texas and exploratory drilling in certain of our emerging plays.

 

Purchases of minerals-in-place.  Purchases of minerals-in-place are primarily attributable to the acquisition of the Henry Properties.

 

Sales of minerals-in-place.  We had no significant sales of minerals-in-place during 2008.

 

Revisions of previous estimates.  Revisions of previous estimates are comprised of 10.1 MMBoe of negative revisions resulting from commodity price declines and 3.1 MMBoe of negative revision resulting from technical and performance evaluations. The Company’s proved reserves at December 31, 2008 were determined using year-

end NYMEX equivalent prices of $41.00 per Bbl of oil and $5.71 per MMBtu of gas, compared to $92.50 per Bbl of oil and $6.80 per MMBtu of gas at December 31, 2007.

 

The following table presents our total gross and net developed and undeveloped acreage by region at December 31, 2008:

 

 

 

 

 

The following table sets forth the expiration amounts of our gross and net undeveloped acreage at December 31, 2008 by region. Expirations may be less or reduced if production is established and/or continuous development activities are undertaken beyond the primary term of the lease.

 

 

 

 

Productive wells

 

The following table sets forth the number of productive oil and gas wells on our properties at December 31, 2008:

 

 

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 more 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 known 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 properties, we perform title reviews on the most significant properties 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 credit facility, 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.

 

 

We are party to the legal proceedings that are described in Note K of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” We are also party to other proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations.

 

 

We did not submit any matters to a vote of stockholders during the fourth quarter of 2008.

 

 

Our common stock trades on the NYSE under the symbol “CXO.” The following table shows, for the periods indicated, the high and low sales prices for our common stock, as reported on the NYSE.

 

 

The last sale price of our common stock on February 23, 2009 was $20.50 per share, as reported on the NYSE.

 

As of February 23, 2009, there were approximately 13,020 holders of record of our common stock.

 

We have not paid, and do not intend to pay in the foreseeable future, cash dividends on our common stock. Our credit facility prohibits the payment of dividends on our common stock.

 

Neither we nor any “affiliated purchaser” repurchased any of our equity securities during the fourth quarter of the fiscal year ended December 31, 2008.

 

 

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 “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 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. became 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 below for the Chase Group Properties for the years ended December 31, 2005 and 2004 are derived from the audited financial statements of the Chase Group Properties. The historical financial data below for Concho Resources Inc. for the years ended December 31, 2008, 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.