Comstock Resources 10-K 2010
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission File No. 001-03262
5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034
(Address of principal executive offices including zip code)
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No þ
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 registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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):
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o No þ
As of February 26, 2010, there were 47,105,606 shares of common stock outstanding.
The aggregate market value of the common stock held by non-affiliates of the registrant, based on the closing price of common stock on the New York Stock Exchange on June 30, 2009 (the last business day of the registrants most recently completed second fiscal quarter), was $1.5 billion.
Portions of the Definitive Proxy Statement for the 2010 Annual Meeting of Stockholders
are incorporated by reference into Part III of this report.
COMSTOCK RESOURCES, INC.
ANNUAL REPORT ON FORM 10-K
For the Fiscal Year Ended December 31, 2009
The information contained in this report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified by their use of terms such as expect, estimate, anticipate, project, plan, intend, believe and similar terms. All statements, other than statements of historical facts, included in this report, are forward-looking statements, including statements mentioned under Risk Factors and Managements Discussion and Analysis of Financial Condition and Results of Operations, regarding:
Any or all of our forward-looking statements in this report may turn out to be incorrect. They can be affected by a number of factors, including, among others:
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. All references to us, our, we or Comstock mean the registrant, Comstock Resources, Inc. and where applicable, its consolidated subsidiaries.
Bbl means a barrel of U.S. 42 gallons of oil.
Bcf means one billion cubic feet of natural gas.
Bcfe means one billion cubic feet of natural gas equivalent.
Btu means British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.
Completion means the installation of permanent equipment for the production of oil or gas.
Condensate means a hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced and is similar to crude oil.
Development well means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well means a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
GAAP means generally accepted accounting principles in the United States of America.
Gross when used with respect to acres or wells, production or reserves refers to the total acres or wells in which we or another specified person has a working interest.
MBbls means one thousand barrels of oil.
MBbls/d means one thousand barrels of oil per day.
Mcf means one thousand cubic feet of natural gas.
Mcfe means one thousand cubic feet of natural gas equivalent.
MMBbls means one million barrels of oil.
MMBtu means one million British thermal units.
MMcf means one million cubic feet of natural gas.
MMcf/d means one million cubic feet of natural gas per day.
MMcfe/d means one million cubic feet of natural gas equivalent per day.
MMcfe means one million cubic feet of natural gas equivalent.
Net when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by us.
Net production means production we own less royalties and production due others.
Oil means crude oil or condensate.
Operator means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.
PV 10 Value means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. This amount is the same as the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves except that it is determined without deducting future income taxes. Although PV 10 Value is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Because many factors that are unique to any given company affect the amount of estimated future income taxes, the use of a pre-tax measure is helpful to investors when comparing companies in our industry.
Proved developed reserves means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved developed non-producing means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain or (ii) currently behind the pipe in existing wells, which are considered proved by virtue of successful testing or production of offsetting wells.
Proved developed producing means reserves expected to be recovered from currently producing zones under continuation of present operating methods. This category may also include recently completed shut-in gas wells scheduled for connection to a pipeline in the near future.
Proved reserves means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Proved undeveloped reserves means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Recompletion means the completion for production of an existing well bore in another formation from which the well has been previously completed.
Reserve life means the calculation derived by dividing year-end reserves by total production in that year.
Reserve replacement means the calculation derived by dividing additions to reserves from acquisitions, extensions, discoveries and revisions of previous estimates in a year by total production in that year.
Royalty means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowners royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
3-D seismic means an advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.
Working interest means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowners royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.
Workover means operations on a producing well to restore or increase production.
We are a Nevada corporation engaged in the acquisition, development, production and exploration of oil and natural gas. Our common stock is listed and traded on the New York Stock Exchange.
Our oil and gas operations are concentrated in the East Texas/North Louisiana and South Texas regions. Our oil and natural gas properties are estimated to have proved reserves of 725.7 Bcfe with an estimated PV 10 Value of $489.1 million as of December 31, 2009 and a standardized measure of discounted future net cash flows of $426.6 million. Our consolidated proved oil and natural gas reserve base is 94% natural gas and 55% proved developed on a Bcfe basis as of December 31, 2009.
Our proved reserves at December 31, 2009 and our 2009 average daily production are summarized below:
High Quality Properties. Our operations are focused in two primary operating areas, the East Texas/North Louisiana and South Texas regions. Our properties have an average reserve life of approximately 11.1 years and have extensive development and exploration potential. We have an extensive acreage position in our East Texas/North Louisiana region in the Haynesville shale resource play where we have identified 85,589 gross (72,638 net to us) acres prospective for Haynesville shale development.
Successful Exploration and Development Program. In 2009 we spent $345.4 million on exploration and development of our oil and natural gas properties. We drilled 54 wells in 2009, 38.6 net to us, at a cost of $307.0 million. We spent $26.0 million to acquire additional leases in the Haynesville shale, $1.9 million on other leasehold costs and $0.9 million to acquire seismic data. We also spent $9.6 million for recompletions, workovers, abandonment and production facilities. Our drilling activities in 2009 added 350 Bcfe to our proved reserves and drove our 9% production growth in 2009.
Efficient Operator. We operate 90% of our proved oil and natural gas reserve base as of December 31, 2009. As operator we are better able to control operating costs, the timing and plans for future development, the level of drilling and lifting costs and the marketing of production. As an operator, we receive reimbursements for overhead from other working interest owners, which reduces our general and administrative expenses.
Successful Acquisitions. We have had significant growth over the years as a result of our acquisition activity. Since 1991, we have added 984.1 Bcfe of proved oil and natural gas reserves from 36 acquisitions at an average cost of $1.14 per Mcfe. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions. We did not make any acquisitions of producing oil and gas properties in 2008 or 2009.
Pursue Exploration Opportunities. We conduct exploration activities to grow our reserve base and to replace our production each year. In late 2007 we identified the potential in our largest operating region, East Texas/North Louisiana, to explore for natural gas in the Haynesville shale formation, which was below the Cotton Valley, Hosston and Travis Peak sand formations that we have been developing. We drilled eight pilot wells to evaluate the prospectivity of the Haynesville shale in 2007 and 2008. We undertook an active leasing program in 2008 and 2009 to acquire additional acreage where we believed the Haynesville shale formation would be prospective and spent $116.9 million in 2008 and $26.9 million in 2009 to increase our leasehold with Haynesville shale potential to 85,589 gross acres (72,638 net to us). We started the commercial development of the Haynesville shale in late 2008 and drilled two (1.1 net to us) successful horizontal wells. In 2009, our drilling program was primarily focused on exploring and developing our Haynesville shale acreage and we spent approximately $243.6 million drilling 43 (30.7 net to us) Haynesville shale horizontal wells. Our Haynesville shale drilling program added 325 Bcfe to our proved reserves in 2009. We plan to continue to develop our Haynesville shale acreage in 2010 and have budgeted to spend $348.0 million to drill 56 (41.1 net to us) Haynesville shale horizontal wells.
In prior years we have had an active drilling program in our South Texas region utilizing 3-D seismic to identify prospects in the Wilcox and Vicksburg formations. We have reduced our activity in the region in response to lower natural gas prices to focus on the higher return Haynesville shale program. We spent $29.2 million in 2009 to drill five (3.4 net to us) successful wells in South Texas.
Exploit Existing Reserves. We seek to maximize the value of our oil and natural gas properties by increasing production and recoverable reserves through development drilling and workover, recompletion and exploitation activities. We utilize advanced industry technology, including 3-D seismic data, horizontal drilling, improved logging tools, and formation stimulation techniques. During 2009, outside of our Haynesville shale and South Texas drilling programs, we spent $13.3 million to drill six wells (4.5 net to us). We also spent $9.6 million for recompletion and workover activity in 2009.
Maintain Flexible Capital Expenditure Budget. The timing of most of our capital expenditures is discretionary because we have not made any significant long-term capital expenditure commitments except for contracted drilling services. We operate most of the drilling projects in which we participate. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures according to market conditions. We have budgeted to spend approximately $385.0 million on our development and exploration projects in 2010. We intend to primarily use operating cash flow to fund our development and exploration expenditures in 2010 and, to a lesser extent, cash on hand and borrowings under our bank credit facility. We may also make additional property acquisitions in 2010 that would require additional sources of funding. Such sources may include borrowings under our bank credit facility or sales of our equity or debt securities.
Acquire High Quality Properties at Attractive Costs. In prior years we have had a successful track record of increasing our oil and natural gas reserves through opportunistic acquisitions. Since 1991, we have added 984.1 Bcfe of proved oil and natural gas reserves from 36 acquisitions at a total cost of $1.1 billion, or $1.14 per Mcfe. The acquisitions were acquired at an average of 67% of their PV 10 Value in the year the acquisitions were completed. We did not complete any acquisitions of producing oil and gas properties in 2008 or 2009 due to our focus on developing our Haynesville shale properties. In evaluating acquisitions, we apply strict economic and reserve risk criteria. We target properties in our core operating areas with established production and low operating costs that also have potential opportunities to increase production and reserves through exploration and exploitation activities. We also evaluate our existing properties and consider divesting of non-strategic assets when market conditions are favorable.
Primary Operating Areas
The following table summarizes the estimated proved oil and natural gas reserves for our twenty largest field areas as of December 31, 2009:
Approximately 70.3% or 510.2 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 923 producing wells (561.5 net to us) in 28 field areas. We operate 633 of these wells. The largest of our fields in this region are the Logansport, Toledo Bend, Beckville, Waskom, Blocker, Mansfield, Hico-Knowles/Terryville, Darco, Douglass, Cadeville and Longwood fields. Production from this region averaged 107.0 MMcf of natural gas per day and 576 barrels of oil per day during 2009 or 110.4 MMcfe per day. Most of the reserves in this area produce from the upper Jurassic aged Haynesville shale or Cotton Valley formations and the Cretaceous aged Travis Peak/Hosston formation. In 2009, we spent $277.5 million drilling 49 wells (35.3 net to us) and $31.4 million on leasehold costs, workovers and recompletions in this region. Forty-six (32.9 net to us) of the 49 wells we drilled were horizontal wells. Forty-three (30.7 net) of these horizontal wells drilled targeted the Haynesville shale. We plan to spend
approximately $368.0 million in 2010 for drilling activities in this region which will focus primarily on the development of our Haynesville shale properties.
The Logansport field located in DeSoto and Sabine Parishes, Louisiana primarily produces from the Haynesville shale formation at a depth of 11,100 to 11,500 feet and from multiple sands in the Cotton Valley and Hosston formations at an average depth of 8,000 feet. Our proved reserves of 203.5 Bcfe in the Logansport field represent approximately 28% of our proved reserves. We own interests in 190 wells (119.9 net to us) and operate 133 of these wells in this field. During December 2009, net daily production attributable to our interest from this field averaged 61.1 MMcf of natural gas and 50 barrels of oil. In 2009, we drilled 19 (13.8 net to us) Haynesville shale horizontal wells and three (2.4 net to us) Cotton Valley vertical wells at Logansport. In 2010, we plan to drill 27 (18.6 net to us) horizontal Haynesville shale wells in our Logansport field.
The Toledo Bend field in Desoto and Sabine Parishes, Louisiana was discovered in 2008 with our first horizontal Haynesville shale well. In 2009, we drilled 16 (10.1 net to us) Haynesville shale horizontal wells at Toledo Bend. One of these wells successfully tested the Upper Haynesville shale. Production from the Lower Haynesville shale in the Toledo Bend ranges from 11,400 to 11,800 feet and from 10,880 to 11,300 in the Upper Haynesville shale. Our proved reserves of 104.1 Bcfe in the Toledo Bend field represent approximately 14.3% of our reserves. We own interests in 15 producing wells (9.3 net to us) and operate ten of these wells. At December 31, 2009 we had three wells (2.3 net to us) that were in the process of being drilled and two wells (1.8 net to us) in the process of being completed. During December 2009, net daily production attributable to our interest from this field averaged 23.7 MMcf of natural gas. In 2010, we plan to drill 25 (19.2 net to us) horizontal Haynesville shale wells in this field.
The Beckville field, located in Panola and Rusk Counties, Texas, has estimated proved reserves of 55.0 Bcfe which represents approximately 7.6% of our proved reserves. We operate 193 wells in this field and own interests in 78 additional wells for a total of 271 wells (162.4 net to us). During December 2009, production attributable to our interest from this field averaged 12.4 MMcf of natural gas per day and 60 barrels of oil per day. The Beckville field produces primarily from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. The field is also prospective for future Haynesville shale development.
The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 5.1% (37.0 Bcfe) of our proved reserves as of December 31, 2009. We own interests in 75 wells in this field (48.7 net to us) and operate 57 wells in this field. During December 2009, net daily production attributable to our interest averaged 5.3 MMcf of natural gas and 45 barrels of oil from this field. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet and from the Haynesville shale formation at depths of 10,800 to 10,900 feet. In 2009, we drilled two successful horizontal Cotton Valley wells and one Haynesville shale well in the Waskom field. In 2010, we plan to drill one (.8 net to us) horizontal Haynesville shale well in the Waskom field.
Our proved reserves of 25.6 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 3.5% of our proved reserves. We own interests in 77 wells (71.3 net to us) and operate 72 of these wells. During December 2009, net daily production attributable to our interest from this field averaged 9.8 MMcf of natural gas and 35 barrels of oil. Most of this production is from the Cotton Valley formation between 8,600 and 10,150 feet and the Haynesville shale formation between 11,100 and 11,450 feet. During 2009 we drilled three successful Haynesville shale horizontal wells and one Cotton Valley horizontal well at Blocker. In 2010, we plan to drill one Haynesville shale horizontal and one Cotton Valley vertical well at Blocker.
The Mansfield field is located in DeSoto Parish Louisiana and produces from the Haynesville shale between 12,250 and 12,350 feet. During 2009 we drilled three (1.9 net to us) Haynesville shale horizontal wells. Our proved reserves in this field of 21.3 Bcfe represent approximately 2.9% of our reserves. During 2010 we plan to drill two (1.5 net to us) horizontal Haynesville shale wells at Mansfield. During December 2009, net daily production attributable to our interest for this field averaged 8.0 MMcf of natural gas.
We have 15.8 Bcfe of proved reserves in the Hico-Knowles/Terryville field area located in Lincoln County, Louisiana which represent approximately 2.2% of our reserves. We own interests in 71 wells (25.9 net to us) and operate 23 of these wells. This field produces primarily from the Hosston/Cotton Valley formations between 7,200 and 11,000 feet. During December 2009, net daily production attributable to our interest from this field averaged 7.2 MMcf of natural gas and 190 barrels of oil.
The Darco field is located in Harrison County, Texas and produces from the Cotton Valley formation at depths from approximately 9,800 to 10,200 feet. Our proved reserves of 12.1 Bcfe in the Darco field represent approximately 1.7% of our reserves. We own interests in 24 wells (18.8 net to us) and operate all of these wells. During December 2009, net daily production attributable to our interest from this field averaged 1.4 MMcf of natural gas and 6 barrels of oil.
The Douglass field is located in Nacogdoches County, Texas and is productive from stratigraphically trapped reservoirs in the Pettet Lime and Travis Peak formations. These reservoirs are found at depths from 9,200 to 10,300 feet. Our proved reserves of 7.8 Bcfe in the Douglass field represent approximately 1.1% of our reserves. We own interests in 42 wells (26.9 net to us) and operate 34 of these wells. During December 2009, net daily production attributable to our interest from this field averaged 1.7 MMcf of natural gas.
Our proved reserves of 7.1 Bcfe in the Cadeville field located in Ouachita Parrish, Louisiana represent approximately 1.0% of our reserves. We own interests in seven wells (4.0 net to us) and operate five of these wells. During December 2009, net daily production attributable to our interest from this field averaged 0.4 MMcf of natural gas and 1 barrel of oil. This production is primarily from the Cotton Valley formation between 9,800 and 10,700 feet.
The Longwood field located in Harrison County, Texas primarily produces from stacked sandstone reservoirs of the Travis Peak and Cotton Valley formations at depths ranging from 6,000 to 10,000 feet and the Haynesville shale formation at depths ranging from 10,450 to 10,750. We own interests in 25 wells in this field, 20.6 net to us, and operate 22 wells in this field. Our proved reserves of 4.5 Bcfe in the Longwood field represent approximately 0.6% of our total reserves. We drilled one (1.0 net to us) successful Haynesville shale horizontal well in this field during 2009. During December 2009, net daily production attributable to our interest from this field averaged 1.3 MMcf of natural gas and 2 barrels of oil.
Approximately 22.2%, or 161.3 Bcfe, of our proved reserves are located in South Texas, where we own interests in 236 producing wells (125.6 net to us). We own interests in 16 field areas in the region, the largest of which are the Fandango, Double A Wells, Rosita, Las Hermanitas, Javelina and Ball Ranch fields. Net daily production rates from this region averaged 51.8 MMcf of natural gas and 448 barrels of oil during 2009 or 54.5 MMcfe per day. We spent $34.7 million in this region in 2009 to drill five successful wells (3.4 net to us) and for other development activity. We plan to spend approximately $12.0 million in 2010 for development and exploration activity in this region.
We own interests in 21 natural gas wells (21.0 net to us) in the Fandango field, located in Zapata County, Texas. We operate all of these wells which produce from the Wilcox formation at depths from approximately 13,000 to 18,000 feet. Our proved reserves of 54.2 Bcfe in this field represent approximately 7.5% of our total reserves. Production from this field averaged 17.2 MMcf of natural gas per day during December 2009. We have drilled one successful exploration well in 2008 and two successful development wells in 2009 since we acquired this field as part of the Shell Wilcox acquisition in December 2007.
Our properties in the Double A Wells field have proved reserves of 32.4 Bcfe, which represent 4.5% of our reserves. We own interests in and operate 59 producing wells (28.6 net to us) in this field in Polk County, Texas. Net daily production from the Double A Wells area averaged 5.2 MMcf of natural gas and 170 barrels of oil during December 2009. These wells produce from the Woodbine formation at an average depth of 14,300 feet.
We own interests in 32 natural gas wells (17.3 net to us) in the Rosita field, located in Duval County, Texas. We operate four of these wells which produce from the Wilcox formation at depths from approximately 9,300 to 17,000 feet. Our proved reserves of 31.4 Bcfe in this field represent approximately 4.3% of our total reserves. Production from this field averaged 4.5 MMcf of natural gas per day during December 2009. We acquired our interest in the field in the Shell Wilcox acquisition in December 2007.
We own interests in and operate 15 natural gas wells (12.2 net to us) in the Las Hermanitas field, located in Duval County, Texas. These wells produce from the Wilcox formation at depths from approximately 11,400 to 11,800 feet. Our proved reserves of 14.4 Bcfe in this field represent approximately 2.0% of our proved reserves. During December 2009, net daily production attributable to our interest from this
field averaged 5.1 MMcf of natural gas. We acquired interests in this field in 2006 and have subsequently drilled eleven successful wells in this field since the acquisition.
We own interests in 17 natural gas wells and one oil well, 18 net to us, in the Javelina field in Hidalgo County in South Texas. These wells produce primarily from the Vicksburg formation at a depth of approximately 10,900 to 12,500 feet. Proved reserves attributable to our interests in the Javelina field are 13.3 Bcfe, which represents 1.8% of our total proved reserves. During December 2009, production attributable to our interest from this field averaged 5.8 MMcf of natural gas per day and 50 barrels of oil per day.
The Ball Ranch field is located in Kenedy County in South Texas and produces from the Vicksburg formation at depths of approximately 11,700 and 14,600 feet. We have interests in 34 producing wells (7.8 net to us) in this field. The proved reserves in this field of 4.0 Bcfe represent 1% of our total proved reserves. During 2009 we drilled three (1.4 net to us) successful wells in this field. During December 2009, net daily production attributable to our interests in this field averaged 5.1 MMcf of natural gas and 40 barrels of oil per day.
Approximately 7.5%, or 54.1 Bcfe, of our proved reserves are in other regions, primarily in Mississippi, New Mexico, Kentucky and the Mid-Continent regions. Within these regions we own interests in 482 producing wells (216.3 net to us) in 19 fields. Fields with the largest proved reserves include the Laurel field in Laurel, Mississippi, our San Juan Basin properties in New Mexico and our Maxie field in Mississippi. Net daily production from our other regions totaled 7.8 MMcf of natural gas and 1,099 barrels of oil or 14.5 MMcfe per day during 2009.
The Laurel field is located in Jones County, Mississippi near a structurally complex salt dome. We own interests in and operate 52 producing wells (49.1 net to us) in the Laurel field. This fields estimated proved reserves of 26.2 Bcfe represent 3.6% of our reserves. The field produces from more than 42 horizons that range in depth from 6,600 feet in the Stanley sand to 13,100 feet in the Middle Hosston formation. Recovery of low viscosity crude oil from this field is being enhanced through waterflood operations. During December 2009, net daily production attributable to our interests in this field averaged 975 barrels of oil per day.
Our San Juan Basin properties are located in the west-central portion of the basin in San Juan County, New Mexico. These wells produce from multiple sands of the Cretaceous Dakota formation and the Fruitland Coal seams. The Dakota is generally found at about 6,000 feet with the shallower Fruitland seams encountered at 2,500 to 3,000 feet. Our proved reserves of 4.7 Bcfe in the San Juan field represent approximately 0.6% of our reserves. We own interests in 97 wells (14.6 net to us) in this field. During December 2009, net daily production attributable to our interest from this field averaged 1.1 MMcf of natural gas and 5 barrels of oil.
The Maxie field is located along the southern boundary of the Mississippi Salt Basin and northern edge of Wiggins Arch in Forrest and Pearl River Counties in Mississippi. Maxie is primarily a gas field producing from Upper Cretaceous Sands and Lower Eocene Wilcox Sands. Our proved reserves of 3.7 Bcfe in the Maxie field represent approximately 1% of our reserves. We own interests in and operate three wells (2.1 net to us) in this field. During December 2009, net daily production attributable to our interest from this field averaged 0.9 MMcf of natural gas and 25 barrels of oil.
As a result of our acquisitions, we have added 984.1 Bcfe of proved oil and natural gas reserves since 1991. Our largest acquisitions include the following:
Shell Wilcox Acquisition. In December 2007, we completed the acquisition of certain oil and natural gas properties and related assets from SWEPI LP, an affiliate of Shell Oil Company (Shell) for $160.1 million. The properties acquired had estimated proved reserves of approximately 70.1 Bcfe. Major fields acquired in the acquisition include the Fandango and Rosita fields. The acquisition was funded with borrowings under our bank credit facility.
Javelina Acquisition. In June 2007 we acquired additional working interests in oil and gas properties in the Javelina field in South Texas from Abaco Operating LLC for $31.2 million. The properties acquired had estimated proved reserves of approximately 9.1 Bcfe. The transaction was funded with borrowings under our bank credit facility.
Denali Acquisition. In September 2006 we acquired proved and unproved oil and gas properties in the Las Hermanitas field in South Texas from Denali Oil & Gas Partners LP and other working interest owners for $67.2 million. The properties acquired had estimated proved reserves of approximately 16.5 Bcfe. The transaction was funded with borrowings under our bank credit facility.
Ensight Acquisition. In May 2005, we completed the acquisition of certain oil and natural gas properties and related assets from Ensight Energy Partners, L.P., Laurel Production, LLC, Fairfield Midstream Services, LLC and Ensight Energy Management, LLC (collectively, Ensight) for $190.9 million. We also purchased additional interests in those properties from other owners for $10.9 million in July 2005. The properties acquired had estimated proved reserves of approximately 121.5 billion cubic feet of natural gas equivalent and included 312 active wells, of which 119 are operated by us. Major fields acquired include the Darco, Douglass, Cadeville, and Laurel fields. The acquisition was funded with proceeds from a public stock offering completed in April 2005 and borrowings under our bank credit facility.
Ovation Energy Acquisition. In October 2004, we acquired producing oil and gas properties in the East Texas, Arkoma, Anadarko and San Juan basins from Ovation Energy, L.P. for $62.0 million. The properties acquired had estimated proved reserves of approximately 41.0 billion cubic feet of gas equivalent and included 165 active wells, of which 69 were operated by us. The acquisition was funded by borrowings under our bank credit facility.
DevX Energy Acquisition. In December 2001, we completed the acquisition of DevX Energy, Inc. (DevX) by acquiring 100% of the common stock of DevX for $92.6 million. The total purchase price including debt and other liabilities assumed in the acquisition was $160.8 million. As a result of the acquisition of DevX, we acquired interests in 600 producing oil and natural gas wells located onshore
primarily in East and South Texas, Kentucky, Oklahoma and Kansas. DevXs properties had 1.2 MMBbls of oil reserves and 156.5 Bcf of natural gas reserves at the time of the acquisition.
Bois dArc Acquisition. In December 1997, Comstock acquired working interests in certain producing offshore Louisiana oil and gas properties as well as interests in undeveloped offshore oil and natural gas leases for approximately $200.9 million from Bois dArc Resources and certain of its affiliates and working interest partners. We acquired interests in 43 wells (29.6 net to us) and eight separate production complexes located in the Gulf of Mexico offshore of Plaquemines and Terrebonne Parishes, Louisiana. The acquisition included interests in the Louisiana state and federal offshore areas of Main Pass Block 21, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved reserves acquired in this acquisition were estimated at 14.3 MMBbls of oil and 29.4 Bcf of natural gas. We divested of these offshore properties in 2008.
Black Stone Acquisition. In May 1996, we acquired 100% of the capital stock of Black Stone Oil Company and interests in producing and undeveloped oil and gas properties located in South Texas for $100.4 million. We acquired interests in 19 wells (7.7 net to us) that were located in the Double A Wells field in Polk County, Texas and we became the operator of most of the wells in the field. The net proved reserves acquired in this acquisition were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas.
Sonat Acquisition. In July 1995, we purchased interests in certain producing oil and gas properties located in East Texas and North Louisiana from Sonat Inc. for $48.1 million. We acquired interests in 319 producing wells (188.0 net to us). The acquisition included interests in the Logansport, Beckville, Waskom, Blocker and Hico-Knowles fields. The net proved reserves acquired in this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas.
The following table sets forth our estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2009:
The following table sets forth our year end reserves as of December 31 for each of the last three fiscal years:
Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.
The average prices that we realized from sales of oil and natural gas, including the effect of hedging, and lifting costs excluding severance and ad valorem taxes, for each of the last three fiscal years were as follows:
The oil and natural gas prices used for reserves estimation were as follows:
We adopted the new rules relating to the estimation and disclosure of oil and natural gas reserves as of December 31, 2009 that were established by the Securities and Exchange Commission (SEC). The PV 10 Value and standardized measure of discounted future net cash flows for 2009 were determined based on the simple average of the first of month market prices for oil and natural gas during 2009 which, after basis adjustments, were $49.60 per barrel for oil and $3.54 per Mcf for natural gas. Under the prior rules the prices would have been based on the market prices at December 31, 2009, which would have been, after basis adjustments, $64.43 per barrel for oil and $5.29 per Mcf for natural gas. The following table shows the sensitivity of our total 2009 proved reserves to prices between the average prices used and the year end
market prices that would have been used had we applied the same pricing methodology that was in effect for 2007 and 2008 in 2009:
The new rules also revised the guidelines for reporting proved undeveloped reserves. Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered, and they are scheduled to be drilled within five years of their initial inclusion as proved reserves, unless specific circumstances justify a longer time. In addition, undeveloped reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
As of December 31, 2009, our proved reserves included 2.3 MMBbls of crude oil and 315 Bcf of natural gas, for a total of 329 Bcfe of undeveloped reserves. Approximately 68% of our proved undeveloped reserves at the end of 2009 were associated with the future development of our Haynesville shale properties. The remaining proved undeveloped reserves are primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and our Wilcox and Vicksburg reservoirs in South Texas. Estimated future costs relating to the development of the undeveloped reserves are projected to be approximately $669.8 million, of which $85.1 million, $245.8 million and $169.5 million are expected to be incurred in 2010, 2011 and 2012, respectively. Costs incurred relating to the development of our undeveloped reserves were approximately $122.2 million, $104.4 million and $20.1 million in 2007, 2008 and 2009, respectively.
Our drilling activities in 2008 resulted in the conversion of 53 wells from proved undeveloped reserves to proved developed producing reserves at the end of 2008. These wells are primarily in our East Texas/North Louisiana and South Texas regions where our 2008 drilling program was primarily focused on exploitation of reserves in the Cotton Valley, Hosston, Vicksburg and Wilcox formations. Following the initial success of our Haynesville shale evaluation wells, our 2009 drilling program was refocused primarily to further evaluate and develop acreage that is prospective in the Haynesville shale formation. As a result, only six of the wells we drilled in 2009 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at the end of 2009. In the course of evaluating our proved undeveloped reserves in accordance with the SECs new reserve estimation rules, we determined that approximately 49 Bcfe of our proved undeveloped reserves as of December 31, 2008 would not be developed within the required five year period and therefore these reserves were excluded from our proved undeveloped reserves at December 31, 2009.
All undeveloped drilling locations which comprise our undeveloped reserves at the end of 2009 are scheduled to be drilled within five years of the first year that such reserves were included in our reported reserves except for 20 Bcfe. We have substantial acreage in our East Texas/North Louisiana region which is productive in the Cotton Valley and Hosston sand reservoirs. Prior to 2008, we actively pursued exploitation of the reserves in these formations, and substantially all of this acreage is held by production. Our focus in 2009 on our Haynesville shale program required us to partially reschedule development of much of our Cotton Valley and Hosston sand reserves to future periods. These reserves, which are on acreage that is currently being developed in the deeper Haynesville shale formation, will be developed after the Haynesville shale formation is developed.
We had proved reserve additions of 325 Bcfe in 2009 relating to discoveries resulting from our Haynesville shale drilling program. These reserve additions related to 109 Bcfe assigned to 43 (30.7 net to us) producing Haynesville shale wells that we drilled and 216 Bcfe assigned to 75 (56.8 net to us) proved
undeveloped locations offsetting these wells. Direct offsets to the forty-three producing Haynesville shale wells accounted for 185 Bcfe of the 216 Bcfe total proved undeveloped reserves added. The remaining 31 Bcfe are attributable to additional offset locations that are not a direct offset to a producing Haynesville shale well. The inclusion of these eight additional proved locations as proved undeveloped reserves is based on a combination of data that demonstrates consistency across the reservoir including log data, pressure data, seismic data and production performance.
The estimates of our oil and natural gas reserves were determined by Lee Keeling and Associates, Inc. (Lee Keeling), an independent petroleum engineering firm. Lee Keeling has been providing consulting engineering and geological services for over fifty years. Lee Keelings professional staff is comprised of qualified petroleum engineers who are experienced in all productive areas of the United States.
Our policies regarding internal controls over the recording of reserves estimates requires that such estimates are in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Inputs to our reserves estimation process, which we provide to Lee Keeling for use in their reserves evaluation, are based upon our historical results for production history, oil and natural gas prices, lifting and development costs, ownership interests and other required data. Our reservoir management group, comprised of qualified petroleum engineers, works with Lee Keeling to ensure that all data provided by us is properly reflected in the final reserves estimates and consults with Lee Keeling throughout the reserves estimation process on technical questions regarding the reserve estimates.
We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2007, 2008 or 2009 to any federal authority or agency, other than the SEC.
Drilling Activity Summary
During the three-year period ended December 31, 2009, we drilled development and exploratory wells as set forth in the table below:
In 2010 to the date of this report, we have drilled five wells (4.1 net to us) and we have seven wells (4.4 net to us) that were in the process of drilling.
The following table sets forth the gross and net producing oil and natural gas wells in which we owned an interest at December 31, 2009:
We operate 950 of the 1,641 producing wells presented in the above table. As of December 31, 2009, we owned interests in 19 wells containing multiple completions, which means that a well is producing from more than one completed zone. Wells with more than one completion are reflected as one well in the table above.
The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2009, all of which is onshore in the continental United States. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.
Our undeveloped acreage expires as follows:
Title to our oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of our oil and natural gas properties are pledged as collateral under our bank credit facility. As is customary in the oil and gas industry, we are generally able to retain our ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease or by payment of delay rentals.
The market for oil and natural gas produced by us depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Our oil production is sold under short-term contracts with a duration of six months or less. The contracts require the purchasers to purchase the amount of oil production that is available at prices tied to the spot oil markets. Our natural gas production is primarily sold under contracts with various terms and priced on first of the month index prices or on daily spot market prices. Approximately 68% of our 2009 natural gas sales were priced utilizing index prices and approximately 32% were priced utilizing daily spot prices. BP Energy Company and Shell Oil Company and its subsidiaries accounted for 22% and 11%, respectively, of our total 2009 sales. The loss of these customers would not have a material adverse effect on us as there is an available market for our crude oil and natural gas production from other purchasers.
With the significant increase in our natural gas production in Northwest Louisiana attributable to our Haynesville shale drilling program, we have entered into longer term marketing arrangements to insure that we have adequate transportation to get our natural gas production to the markets. As an alternative to constructing our own gathering and treating facilities, we have entered into a variety of gathering and treating agreements with midstream companies to transport our natural gas to the long-haul natural gas pipelines. We have dedicated our production in our Logansport and Toledo Bend fields under such agreements for terms which expire from 2016 to 2018. We have a commitment to transport a minimum of 12 Bcf over four years under one of these agreements.
We have also entered into certain agreements with a major natural gas marketing company to provide us with firm transportation and markets for our Northwest Louisiana natural gas production on the long-haul pipelines. Under these agreements, we have priority access at certain delivery points for 85,000 MMBtus per day expanding to 145,000 MMBtus per day by mid 2010. These agreements expire from 2012 to 2019. To the extent we are not able to deliver the contracted natural gas volumes, we may be responsible for the transportation costs. Our production available to deliver under these agreements in Northwest Louisiana is expected to exceed the firm transportation arrangements we have in place. In addition, the marketing company managing the firm transportation is required to use reasonable efforts to supplement our deliveries should we have a shortfall during the term of the agreements.
The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of oil and natural gas properties and leases for oil and gas exploration.
General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission, or FERC, regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or NGA, and the Natural Gas Policy Act of 1978, or NGPA. In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting all first sales of natural gas, effective January 1, 1993, subject to the terms of any private contracts that may be in effect. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business. Under the provisions of the Energy Policy Act of 2005 (the 2005 Act), the NGA has been amended to prohibit any form of market manipulation with the purchase or sale of natural gas, and the FERC has issued new regulations that are intended to increase natural gas pricing transparency. The 2005 Act has also significantly increased the penalties for violations of the NGA.
Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the traditional role of interstate pipelines as wholesalers of natural gas in favor of providing storage and transportation services.
In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERCs pricing policy by waiving price ceilings for short-term released capacity for an experimental period, and effected changes in the FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. While most major aspects of Order No. 637 have been upheld on judicial review, certain issues such as capacity segmentation and right of first refusal are pending further consideration by the FERC. We cannot predict what action the FERC will take on these matters in the future or whether the FERCs actions will survive further judicial review.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes by these state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that we will be affected differently than other natural gas producers with which we compete by any action taken.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very
heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC, Congress and state regulatory authorities will continue.
Federal leases. Some of our operations are located on federal oil and natural gas leases that are administered by the Bureau of Land Management (BLM) of the United States Department of the Interior. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and BLM regulations and orders that are subject to interpretation and change. These leases are also subject to certain regulations and orders promulgated by the Department of Interiors Minerals Management Service (MMS), through its Minerals Revenue Management Program, which is responsible for the management of revenues from both onshore and offshore leases. Additionally, some of our federal leases are subject to the Indian Mineral Development Act of 1982, and are therefore subject to supplemental regulations and orders of the Department of Interiors Bureau of Indian Affairs. While we cannot predict how various federal agencies may change their interpretations of existing regulations and orders or how regulations and orders issued in the future will impact our operations located on these federal leases, we do not believe we will be affected differently than other similarly situated oil and natural gas producers.
Oil and natural gas liquids transportation rates. Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The price received from the sale of these products may be affected by the cost of transporting the products to market.
The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERCs regulation of natural gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge a market-based rate if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing oil rate-indexing method. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another five-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC increased its index slightly. A challenge to FERCs remand order was denied by the D.C. Circuit in April 2004.
With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the
absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids producers or marketers.
Environmental regulations. We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup cost without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.
We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements or new regulatory schemes such as carbon cap and trade programs could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.
The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, or RCRA, regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as hazardous waste. Disposal of such non-hazardous oil and natural gas exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this
exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from RCRAs definition of hazardous wastes, thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating cost, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.
Our operations are also subject to the Clean Air Act, or CAA, and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.
The Federal Water Pollution Control Act of 1972, as amended, or the Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
Federal regulators require certain owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous requirements relating to the prevention and response to oil spills in the waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages relating to a spill. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.
Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or MPAs, in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development projects and/or causing us to incur increased operating expenses.
Certain flora and fauna that have officially been classified as threatened or endangered are protected by the Endangered Species Act. This law prohibits any activities that could take a protected
plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed and/or expensive mitigation might be required.
Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Oil Pollution Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.
Changes in environmental laws and regulations which result in more stringent and costly reporting, waste handling, storage, transportation, disposal or cleanup activities could materially affect companies operating in the energy industry. Climate change regulation, primarily focused on regulating emissions of certain gases such as methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas, is under consideration by the U.S. Congress and various state governments. Adoption of new laws and regulations that regulate or restrict emissions of gases such as methane or carbon dioxide, or which levy taxes or other costs on such emissions, could result in changes to the consumption and demand for natural gas, which could adversely affect our business, financial position, results of operations and prospects. We may also be assessed administrative, civil and/or criminal penalties if we fail to comply with any such new laws and regulations.
We maintain insurance against sudden and accidental occurrences, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such cost or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.
Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.
State regulation. Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.
Our executive offices are located at 5300 Town and Country Blvd., Suite 500 in Frisco, Texas 75034 and our telephone number is (972) 668-8800. We lease office space in Frisco, Texas covering 53,364 square feet at a monthly rate of $100,057. This lease expires on July 31, 2014. We also own production offices and pipe yard facilities near Marshall, Livingston, and Zapata, Texas; Logansport, Louisiana; Guston, Kentucky and Laurel, Mississippi.
As of December 31, 2009, we had 130 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.
The following table sets forth certain information concerning our executive officers and directors.
A brief biography of each person who serves as a director or executive officer follows below.
M. Jay Allison has been a director since 1987, and our President and Chief Executive Officer since 1988. Mr. Allison was elected Chairman of the board of directors in 1997. From 1987 to 1988, Mr. Allison served as our Vice President and Secretary. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. Mr. Allison was Chairman of the Board of Directors of Bois dArc Energy, Inc. from the time of its formation in 2004 until its merger with Stone Energy Corporation in August 2008. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison also currently serves as a Director of Tidewater Marine, Inc., and on the Advisory Board of the Salvation Army in Dallas, Texas.
Roland O. Burns has been our Senior Vice President since 1994, Chief Financial Officer and Treasurer since 1990, our Secretary since 1991 and a director since 1999. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen. During his tenure with Arthur Andersen, Mr. Burns worked primarily in the firms oil and gas audit practice. Mr. Burns was a director, Senior Vice President and the Chief Financial Officer of Bois dArc Energy, Inc. from the time of its formation in 2004
until its merger with Stone Energy Corporation in August 2008. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.
D. Dale Gillette has been our Vice President of Land and General Counsel since 2006. Prior to joining us, Mr. Gillette practiced law extensively in the energy sector for 32 years, most recently as a partner with Gardere Wynne Sewell LLP, and before that with Locke Liddell & Sapp LLP. During that time he represented independent exploration and production companies and large financial institutions in numerous oil and gas transactions. Mr. Gillette has also served as corporate counsel in the legal department of Mesa Petroleum Co. and in the legal department of Enserch Corp. Mr. Gillette holds B.A. and J.D. degrees from the University of Texas and is a member of the State Bar of Texas.
Mack D. Good was appointed our Chief Operating Officer in 2004. From 1999 to 2004, he served as Vice President of Operations. From August 1997 until February 1999, Mr. Good served as our district engineer for the East Texas/North Louisiana region. From 1983 until July 1997, Mr. Good was with Enserch Exploration, Inc. serving in various operations management and engineering positions. Mr. Good received a B.S. of Biology/Chemistry from Oklahoma State University in 1975 and a B.S. of Petroleum Engineering from the University of Tulsa in 1983. He is a Registered Professional Engineer in the State of Texas.
Stephen E. Neukom has been our Vice President of Marketing since 1997 and has served as our manager of crude oil and natural gas marketing since December 1996. From October 1994 to 1996, Mr. Neukom served as vice president of Comstock Natural Gas, Inc., our former wholly owned gas marketing subsidiary. Prior to joining us, Mr. Neukom was senior vice president of Victoria Gas Corporation from 1987 to 1994. Mr. Neukom received a B.B.A. degree from the University of Texas in 1972.
Daniel K. Presley has been our Vice President of Accounting since 1997 and has been with us since December 1989, serving as controller since 1991. Prior to joining us, Mr. Presley had six years of experience with several independent oil and gas companies including AmBrit Energy, Inc. Prior thereto, Mr. Presley spent two and one-half years with B.D.O. Seidman, a public accounting firm. Mr. Presley received a B.B.A. from Texas A & M University in 1983.
Richard D. Singer has been our Vice President of Financial Reporting since 2005. Mr. Singer has over 30 years of experience in financial accounting and reporting. Prior to joining us, Mr. Singer most recently served as an assistant controller for Holly Corporation from March 2004 to May 2005 and as assistant controller for Santa Fe International Corporation from July 1988 to December 2002. Mr. Singer received a B.S. degree from the Pennsylvania State University in 1976 and is a Certified Public Accountant.
David K. Lockett has served as a director since 2001. Mr. Lockett is a Vice President with Dell Inc. and has held executive management positions in several divisions within Dell since 1991. Mr. Lockett has been employed by Dell Inc. for the past 18 years and has been in the technology industry for the past 33 years. Mr. Lockett was a director of Bois dArc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.
Cecil E. Martin has served as a director since 1988. Mr. Martin is an independent commercial real estate investor who has primarily been managing his personal real estate investments since 1991. From 1973 to 1991, he also served as chairman of a public accounting firm in Richmond, Virginia. Mr. Martin was a director and chairman of the Audit Committee of Bois dArc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Martin also serves on the board of directors of Crosstex
Energy, Inc. and Crosstex Energy, L.P. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.
David W. Sledge has served as a director since 1996. Mr. Sledge was President and Chief Operating Officer of Sledge Drilling Company until it was acquired by Basic Energy Services, Inc. in April 2007 and served as a Vice President of Basic Energy Services, Inc. from April 2007 to February 2009. He served as an area operations manager for Patterson-UTI Energy, Inc. from May 2004 until January 2006. From October 1996 until May 2004, Mr. Sledge managed his personal investments in oil and gas exploration activities. Mr. Sledge was a Director of Bois dArc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Sledge is a past director of the International Association of Drilling Contractors and is a past chairman of the Permian Basin chapter of this association. He received a B.B.A. degree from Baylor University in 1979.
Nancy E. Underwood has served as a director since 2004. Ms. Underwood is owner and President of Underwood Financial Ltd., a position she has held since 1986. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining River Hill Development Corporation in 1981. Ms. Underwood currently serves on the Executive Board and Campaign Steering Committee of the Southern Methodist University Dedman School of Law and on the board of the Presbyterian Hospital of Dallas Foundation.
Our executive offices are located at 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034. Our telephone number is (972) 668-8800. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The public may read and copy any materials that we file with the SEC at the SECs 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. In addition, the SEC maintains a website that contains reports, proxy and information statements, and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge on our website (www.comstockresources.com) our Annual Report on Form 10-K, 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 file such material with, or furnish it to, the SEC.
You should carefully consider the following risk factors as well as the other information contained or incorporated by reference in this report, as these important factors, among others, could cause our actual results to differ from our expected or historical results. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all of our potential risks or uncertainties.
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.
Our business is heavily dependent upon the prices of, and demand for, oil and natural gas. Historically, the prices for oil and natural gas have been volatile and are likely to remain volatile in the future. The prices
we receive for our oil and natural gas production and the level of such production will be subject to wide fluctuations and depend on numerous factors beyond our control, including the following:
If the decline in the price of crude oil or natural gas that first started in 2008 continues again during 2010, the lower prices will adversely affect:
In the future we may enter into hedging arrangements in order to reduce our exposure to price risks. Such arrangements would limit our ability to benefit from increases in oil and natural gas prices.
The current recession could have a material adverse impact on our financial position, results of operations and cash flows.
The oil and gas industry is cyclical and tends to reflect general economic conditions. The United States and other countries are in a recession which could last through 2010 and beyond, and the capital markets are experiencing significant volatility. The recession has had an adverse impact on demand and pricing for crude oil and natural gas. A continuation of the recession could have a further negative impact on oil and natural gas prices. Our operating cash flows and profitability will be significantly affected by declining oil and natural gas prices. Further declines in oil and natural gas prices may also impact the value of our oil and gas reserves, which could result in future impairment charges to reduce the carrying value of our oil and gas properties and our marketable securities. Our future access to capital could be limited due to tightening credit markets and volatile capital markets. If our access to capital is limited, development of our assets may be delayed or limited, and we may not be able to execute our growth strategy.
Our future production and revenues depend upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we must continue our acquisition and drilling activities. We cannot assure you, however, that our acquisition and drilling activities will result in significant additional reserves or that we will have continuing success drilling productive wells at low finding and development costs. Furthermore, while our revenues may
increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.
A prospect is a property in which we own an interest or have operating rights and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return.
Federal hydraulic fracturing legislation could increase our costs and restrict our access to our oil and gas reserves.
Several proposals are before the United States Congress that, if implemented, would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs including the Haynesville shale, Cotton Valley and other tight natural gas reservoirs.
Although it is not possible at this time to predict the final outcome of any legislation regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay or inhibit our ability to develop our oil and natural gas reserves.
The proposed US federal budget for fiscal year 2011 includes certain provisions that, if passed as originally submitted, will have an adverse effect on us.
On February 1, 2010, the federal government released its proposed budget for fiscal year 2011. The proposed budget contains provisions which would impose new taxes and which would repeal many tax incentives and deductions that are currently used by independent oil and gas producers. The provisions being considered that would impact us are: elimination of the ability to fully deduct intangible drilling costs in the year incurred, repeal of the manufacturing tax deduction for oil and gas companies, increasing the geological and geophysical cost amortization period, and implementation of a fee on non-producing leases located on federal lands. If these proposals are enacted, our current income tax liability will increase, potentially significantly, which would have a negative impact on our cash flow from operating activities. A reduction in operating cash flow could require us to reduce our drilling activities. Since none of these proposals have yet to be included in new legislation, we do not know the ultimate impact they may have on our business.
We had $470.8 million in debt as of December 31, 2009, and our ratio of total debt to total capitalization was approximately 31%.
Our outstanding debt will have important consequences, including, without limitation:
In addition, future acquisition or development activities may require us to alter our capitalization significantly. These changes in capitalization may significantly increase our debt. Moreover, our ability to meet our debt service obligations and to reduce our total debt will be dependent upon our future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flow from operations in the future to service our indebtedness and to meet other commitments, we will be required to adopt one or more alternatives, such as refinancing or restructuring our indebtedness, selling material assets or seeking to raise additional debt or equity capital. We cannot assure you that any of these actions could be effected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.
Our bank credit facility contains a number of significant covenants. These covenants will limit our ability to, among other things:
Our failure to comply with any of these covenants could cause a default under our bank credit facility and the respective indentures governing our 67/8% senior notes due 2012 and 83/8% senior notes due 2017. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it given the current status of the credit markets. Even if new financing is available, it may not be on terms that are acceptable to us. Complying with these covenants may cause us to take actions that we otherwise would not take or not take actions that we otherwise would take.
The unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry has experienced a shortage of drilling rigs, equipment, supplies and qualified personnel in recent years as the result of higher demand for these services. Costs and delivery times of rigs, equipment and supplies have been substantially greater than they were several years ago. In addition, demand for, and wage rates of, qualified drilling rig crews have escalated due to the higher activity levels. Shortages of drilling rigs, equipment or supplies or qualified personnel in the areas in which we operate could delay or
restrict our exploration and development operations, which in turn could adversely affect our financial condition and results of operations because of our concentration in those areas.
Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our future success will depend on the success of our exploration and development activities. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas or oil reserves will be discovered. In addition, these activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells can hurt our efforts to replace production and reserves.
Our business involves a variety of operating risks, including:
If we experience any of these problems, well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.
We could also incur substantial losses as a result of:
We pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.
Our growth has been attributable in part to acquisitions of producing properties and companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any
material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.
The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:
In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in the East Texas/North Louisiana and South Texas regions, we may pursue acquisitions or properties located in other geographic areas.
We operate in a highly competitive industry, and our failure to remain competitive with our competitors, many of which have greater resources than we do, could adversely affect our results of operations.
The oil and natural gas industry is highly competitive in the search for and development and acquisition of reserves. Our competitors often include companies that have greater financial and personnel resources than we do. These resources could allow those competitors to price their products and services more aggressively than we can, which could hurt our profitability. Moreover, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to close transactions in a highly competitive environment.
Our competitors may use superior technology that we may be unable to afford or which would require costly investment by us in order to compete.
If our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advances and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. All of these factors may inhibit our ability to acquire additional prospects and compete successfully in the future.
Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities. Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our oil and natural gas reserves.
We expect to expend substantial capital in the acquisition of, exploration for and development of oil and natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares, and may not be possible on terms acceptable to us given the current volatility in the financial markets. The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.
If oil and natural gas prices remain low or continue to decline, we may be required to write-down the carrying values and/or the estimates of total reserves of our oil and natural gas properties, which would constitute a non-cash charge to earnings and adversely affect our results of operations.
Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the total value of our reserves. Such a reduction in carrying value could impact our borrowing ability and may result in accelerating the repayment date of any outstanding debt.
Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves is only estimated and should not be construed as the current market value of the oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding years estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from
changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.
As of December 31, 2009, 45% of our total proved reserves are undeveloped and 10% are developed non-producing. These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may result in a material adverse effect on our results of operations.
If we are unsuccessful at marketing our oil and natural gas at commercially acceptable prices, our profitability will decline.
Our ability to market oil and natural gas at commercially acceptable prices depends on, among other factors, the following:
Our inability to respond appropriately to changes in these factors could negatively affect our profitability.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and processing facilities. Our ability to market our production depends in a substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, in some cases owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of the inadequacy or unavailability of pipelines or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.
We depend on our key personnel and the loss of any of these individuals could have a material adverse effect on our operations.
We believe that the success of our business strategy and our ability to operate profitably depend on the continued employment of M. Jay Allison, our President and Chief Executive Officer, and a limited number of other senior management personnel. Loss of the services of Mr. Allison or any of those other individuals could have a material adverse effect on our operations.
Our insurance coverage may not be sufficient or may not be available to cover some liabilities or losses that we may incur.
If we suffer a significant accident or other loss, our insurance coverage will be net of our deductibles and may not be sufficient to pay the full current market value or current replacement value of our lost investment, which could result in a material adverse impact on our operations and financial condition. Our
insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers compensation laws in dealing with their employees. In addition, some risks, including pollution and environmental risks, generally are not fully insurable.
We are subject to extensive governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:
Under these laws and regulations, we could be liable for:
Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment and otherwise relating to environmental protection. These laws and regulations:
Failure to comply with these laws and regulations may result in:
In June 2009 the United States House of Representatives passed the American Clean Energy and Security Act of 2009. A similar bill, the Clean Energy Jobs and American Power Act, has been introduced in the Senate, but has not passed. Both bills contain the basic feature of establishing a cap and trade system for restricting greenhouse gas emissions in the United States. Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission allowances corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary over time to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of these legislative initiatives remain uncertain. In addition to the pending climate legislation, the EPA has issued the Final Mandatory Reporting of Greenhouse Gases Rule, which requires many suppliers of fossil fuels or industrial chemicals, manufacturers of vehicles and engines, and other facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year to begin collecting greenhouse gas emissions data under a new reporting system beginning on January 1, 2010 with the first annual report due March 31, 2011. Although we currently are not required to report under these new regulations, we may be required to do so in the future. Beyond measuring and reporting, the EPA issued an Endangerment Finding under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The EPA has proposed regulation that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules this year. Since all of our crude oil and natural gas production is in the United States, any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on demand for the crude oil and natural gas we produce.
In January 2010 the Bureau of Land Management announced that it will be issuing a new draft oil and gas leasing policy that will require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources on federal lands, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. As the policy has not yet been released, we are not able to determine the impact these potential leasing policy changes may have on our business.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Future environmental laws and regulations, including proposed legislation regulating climate change, may negatively impact our industry. The costs of compliance with these requirements may have an adverse impact on our financial condition, results of operations and cash flows.
Provisions of our articles of incorporation, bylaws and Nevada law will make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.
Nevada corporate law and our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us. These provisions include:
We have in place a stockholders rights plan. The provisions of the stockholders rights plan and the above provisions could make an acquisition of us by means of a tender offer or proxy contest or removal of our incumbent directors more difficult. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.
We are not a party to any legal proceedings which management believes will have a material adverse effect on our consolidated results of operations or financial condition.
No matters were submitted to a vote of our security holders during the fourth quarter of 2009.
Our common stock is listed for trading on the New York Stock Exchange under the symbol CRK. The following table sets forth, on a per share basis for the periods indicated, the high and low sales prices by calendar quarter for the periods indicated as reported by the New York Stock Exchange.
As of February 26, 2010, we had 47,105,606 shares of common stock outstanding, which were held by 263 holders of record and approximately 15,286 beneficial owners who maintain their shares in street name accounts.
We have never paid cash dividends on our common stock. We presently intend to retain any earnings for the operation and expansion of our business and we do not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant. In addition, we are limited under our bank credit facility and by the terms of the indentures for our senior notes from paying or declaring cash dividends.
During the fourth quarter of 2009, we did not repurchase any of our equity securities.
The following table summarizes certain information regarding our equity compensation plans as of December 31, 2009:
We do not have any equity compensation plans that were not approved by stockholders.
The historical financial data presented in the table below as of and for each of the years in the five-year period ended December 31, 2009 are derived from our consolidated financial statements. The financial results are not necessarily indicative of our future operations or future financial results. The data presented below should be read in conjunction with our consolidated financial statements and the notes thereto and Managements Discussion and Analysis of Financial Condition and Results of Operations. During 2008, we divested our interests in offshore operations which were conducted through our subsidiary Bois dArc Energy, Inc. (Bois dArc). Accordingly, we have adjusted the presentation of selected financial data to reflect the offshore operations on a discontinued basis.
Statement of Operations Data:
The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Risk Factors and Cautionary Note Regarding Forward-Looking Statements.
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas in the United States. We own interests in 1,641 (903.4 net to us) producing oil and natural gas wells and we operate 950 of these wells. In managing our business, we are concerned primarily with maximizing return on our stockholders equity. To accomplish this goal, we focus on profitably increasing our oil and natural gas reserves and production.
Our offshore operations were historically conducted through our subsidiary, Bois dArc. Bois dArc was acquired by Stone Energy Corporation (Stone) in exchange for a combination of cash and shares of Stone common stock on August 28, 2008. Our offshore operations are presented as discontinued operations in our financial statements for all periods presented. Unless indicated otherwise, the amounts in the accompanying tables and discussion relate to our continuing onshore operations. In 2008, we recorded an impairment of $162.7 million ($105.8 million after income taxes) to reduce our carrying value for our investment in Stone common stock to fair market value.
Our future growth will be driven primarily by acquisition, development and exploration activities. In 2009 our growth in production and proved reserves was primarily driven by our successful drilling activities in the Haynesville shale formation. Under our current drilling budget, we plan to spend approximately $385.0 million in 2010 for development and exploration activities which will primarily be focused on developing our Haynesville shale properties. We plan to drill approximately 59 wells (42.6 net to us) in 2010. Fifty-six of these wells will be horizontal Haynesville shale wells. However, we could increase or decrease the number of wells that we drill depending on oil and natural gas prices. We do not budget for acquisitions as the timing and size of acquisitions are not predictable.
We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.
We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future.
Our operating costs are generally comprised of several components, including costs of field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.
Like all oil and natural gas exploration and production companies, we face the constant challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity. Our future growth will depend on our ability to continue to add new reserves in excess of production.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $6.6 million as of December 31, 2009.
Results of Operations
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Our operating data for 2008 and 2009 is summarized below:
Oil and gas sales. Our oil and gas sales decreased $272.8 million (48%) in 2009 to $290.9 million from sales of $563.7 million in 2008. This decrease primarily reflects lower prices realized by us for natural gas and crude oil in 2009. The average price for natural gas realized by us decreased by 53% in 2009 as compared to 2008. Prices for crude oil decreased by 42% in 2009 as compared to 2008. Our production in 2009 increased by 9% over 2008s production as our successful drilling in the Haynesville shale more than replaced the declines from our existing producing properties.
Oil and gas operating expenses. Our oil and gas operating expenses, including production taxes, decreased $17.5 million (20%) to $69.2 million in 2009 from operating expenses of $86.7 million in 2008. Oil and gas operating expenses per equivalent Mcf produced decreased to $1.06 as compared to $1.45 in 2008. The decrease in operating costs mainly reflects lower production taxes resulting from the lower oil and natural gas prices.
Exploration expense. We had $0.9 million in exploration expense in 2009 as compared to $5.0 million in 2008. Exploration expense in 2009 primarily related to costs incurred for the acquisition of seismic data. Exploration expense in 2008 includes the cost of one exploratory dry hole, leasehold impairments and cost incurred for seismic data acquisition.
Depreciation, depletion and amortization expense (DD&A). DD&A increased $31.0 million (17%) to $213.2 million in 2009 from DD&A of $182.2 million in 2008. Our DD&A rate per Mcfe produced averaged $3.25 in 2009 as compared to $3.03 for 2008. DD&A increased due to our higher production level and an increase in the amortization rate.
Impairment of oil and gas properties. We recorded impairments to our oil and gas properties of $0.1 million in 2009 as compared to impairment expense of $0.9 million in 2008. The impairments in 2009 and 2008 relate to fields where an impairment was indicated based on estimated future cash flows attributable to the fields estimated proved oil and natural gas reserves.
General and administrative expenses. General and administrative expenses of $39.2 million for 2009 were 21% higher than general and administrative expenses of $32.3 million for 2008. The increase primarily reflects our higher personnel costs in 2009 due to increased staffing necessary to support our exploration and development activities and an increase of $3.5 million in our stock-based compensation in 2009 as compared to 2008.
Interest expense. Interest expense decreased $9.2 million (37%) to $16.1 million in 2009 from interest expense of $25.3 million in 2008. The decrease was primarily the result of our lower outstanding borrowings and our lower average interest rates in 2009 as well as an increase in capitalized interest related to our unevaluated properties during 2009. Average borrowings under our bank credit facility decreased to $116.8 million in 2009 as compared to $301.5 million for 2008. The average interest rate on the outstanding borrowings under our credit facility decreased to 2.1% in 2009 as compared to 4.5% in 2008. Interest expense in 2009 also includes $6.1 million related to the issuance of $300.0 million of 83/8% senior notes in October 2009. We capitalized interest of $6.6 million and $2.3 million in 2009 and 2008, respectively, which reduced interest expense.
Income taxes. Income tax expense from continuing operations decreased in 2009 to a benefit of $10.8 million from a provision of $38.6 million in 2008. Our effective tax rate of 22.8% in 2009 and our effective tax rate of 39.9% in 2008 differed from federal income tax rate of 35% primarily due to the effect of nondeductible compensation and state income taxes.
Income (loss). We reported a loss of $36.5 million for 2009 as compared to income from continuing operations of $58.2 million for 2008. The loss per diluted share for 2009 was $0.81 on weighted average shares outstanding of 45.0 million as compared to income per share $1.26 for 2008 on weighted average diluted shares outstanding of 44.8 million. The loss in 2009 was primarily attributable to the declines in oil and natural gas prices that we realized.
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Our operating data for 2007 and 2008 is summarized below:
Oil and gas sales. Our oil and gas sales increased $232.1 million (70%) in 2008 to $563.7 million from $331.6 million in 2007. The increase in our sales is primarily due to a 32% increase in our production combined with stronger oil and natural gas prices in 2008. Our realized oil price in 2008 increased by 43% and our realized natural gas price increased by 28% as compared to 2007. Production in 2008 increased by
15% over 2007 as the result of an acquisition of producing properties in South Texas which closed in December 2007. Our successful drilling activity replaced declines from our existing producing properties and accounted for the remaining 17% production increase in 2008.
Oil and gas operating expenses. Our oil and gas operating expenses, including production taxes, increased $21.9 million (34%) to $86.7 million in 2008 from $64.8 million in 2007. Oil and gas operating expenses per equivalent Mcf produced increased $0.02 to $1.45 in 2008 as compared to $1.43 in 2007. The increase in operating costs is due to the start-up of new wells and higher production and ad valorem taxes due to increased oil and gas prices.
Exploration expense. In 2008, we incurred $5.0 million in exploration expense as compared to $7.0 million in 2007. Exploration expense in 2008 primarily relates to one dry hole drilled, the impairment of unevaluated leases and the acquisition of seismic data. Exploration expense in 2007 included costs for four dry holes, leasehold impairments and costs incurred for seismic data acquisition.
DD&A. DD&A increased $56.9 million (45%) to $182.2 million in 2008 from $125.3 million in 2007. This increase resulted from our 32% increase in production in 2008 as compared to 2007 and an increase in our average DD&A rate from $2.76 to $3.03 per Mcfe produced. The increase in the average DD&A rate results from the higher finding costs associated with our property acquisitions and exploration and development activities in 2007 and 2008.
Impairment of oil and gas properties. We recorded impairments to our oil and gas properties of $0.9 million in 2008 and $0.5 million in 2007. The impairments in 2008 and 2007 relate to fields where an impairment was indicated based on estimated future cash flows attributable to the fields estimated proved oil and natural gas reserves.
General and administrative expenses. General and administrative expenses increased $4.5 million (16%) in 2008 to $32.3 million from $27.8 million in 2007. The increase primarily reflects higher personnel costs resulting from increased hiring to support our operating activities and an increase of $1.5 million in stock based compensation in 2008 as compared to 2007.
Interest expense. Interest expense decreased $7.0 million (22%) to $25.3 million in 2008 from $32.3 million in 2007. The decrease was primarily due to lower interest rates in 2008 and the capitalization of interest related to our unevaluated properties on which we are conducting exploration activity. The average interest rate on the outstanding borrowings under our credit facility decreased to 4.5% in 2008 as compared to 6.6% in 2007. We capitalized interest of $2.3 million in 2008 which reduced interest expense. No interest was capitalized in 2007. Average borrowings under our bank credit facility increased to $301.5 million in 2008 as compared to $279.7 million for 2007.
Impairment of marketable securities. We received shares of common stock of Stone from the sale of Bois dArc which were initially valued at $211.4 million. Subsequent to August 2008, the market value of the Stone shares declined significantly. We recognized an impairment charge of $162.7 million in the fourth quarter of 2008 based upon our assessment that this decline is other than temporary.
Income taxes. Income tax expense related to continuing operations increased by $9.4 million to $38.6 million in 2008 from $29.2 million for 2007. Higher income tax expenses in 2008 are primarily due to our higher income. Our effective tax rate of 39.9% for continuing operations in 2008 was comparable to our effective tax rate in 2007 of 39.0%.
Income from continuing operations. We reported income from continuing operations of $58.2 million in 2008, as compared to $45.6 million for 2007. The income per diluted share from continuing operations for
2008 was $1.26 on weighted average diluted shares outstanding of 44.8 million as compared to $1.01 for 2007 on weighted average diluted shares outstanding of 44.1 million. The higher income from continuing operations in 2008 results from higher oil and gas sales reflecting increased production and significantly higher oil and natural gas prices received. Higher revenues were only partially offset by higher operating costs, DD&A expense and general and administrative expense. Impairments of $163.6 million in 2008 reduced our income from continuing operations by $106.4 million.
Income from discontinued operations. Income from discontinued operations was $193.7 million in 2008 as compared to $23.3 million in 2007. The increase in income from discontinued operations in 2008 reflects the higher oil and gas prices in 2008 offset in part by higher operating and exploration expenses of the offshore operations. Also included in income from discontinued operations in 2008 is a net gain, after income taxes, of $158.1 million as a result of the sale of our interest in Bois dArc.
Liquidity and Capital Resources
Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or asset dispositions. Our net cash provided by operating activities from continuing operations in 2009 totaled $176.3 million. Our other primary source of funds in 2009 was $289.2 million of net proceeds from the issuance of senior notes and $135.0 million of borrowings under our bank credit facility. A portion of the cash proceeds from our senior notes offering in 2009 was used to repay the balance outstanding on our bank credit facility. In 2008, our net cash flow provided by operating activities from continuing operations totaled $450.5 million. Our other primary source of funds in 2008 was the after tax proceeds of $421.8 million from the disposition of assets, including sale of our offshore operations. In 2007, our net cash flow provided by operating activities from continuing operations totaled $201.5 million. Our other primary source of funds in 2007 was a net increase of $325.0 million under our bank credit facility.
Our cash flow from operating activities from continuing operations in 2009 decreased by $274.2 million to $176.3 million as compared to 2008 primarily due to lower revenues which were primarily attributable to the lower natural gas and crude oil prices we realized during 2009. Our cash flow from operating activities from continuing operations in 2008 increased by $249.0 million to $450.5 million as compared to $201.5 million in 2007 primarily due to higher revenues which were attributable to our increased production and higher oil and natural gas prices.
Our primary need for capital, in addition to funding our ongoing operations, relates to the acquisition, development and exploration of our oil and gas properties, and the repayment of our debt. In 2009, our capital expenditures of $344.8 million decreased by $81.6 million as compared to 2008 capital expenditures of $426.4 million. During 2009 we initially funded our capital expenditures with operating cash flow and borrowings of $135.0 million under our bank credit facility. In October 2009 we issued $300.0 million of 83/8% senior notes due in 2017 and used the net proceeds from this offering of $289.2 to pay down the balance outstanding under our bank credit facility and to fund current and future capital expenditures. In 2008, we reduced the amount outstanding under our bank credit facility by $470.0 million, primarily by using the proceeds from our asset sales. Our capital expenditures in 2008 of $426.4 million decreased by $100.6 million from 2007 capital expenditures of $527.0 million. Capital expenditures in 2007 included $191.3 million for acquisitions of producing oil and gas properties. In 2008, we spent $113.0 million to acquire unevaluated acreage primarily relating to the exploration of the Haynesville shale formation. We did not acquire any producing oil and natural gas properties in 2008 or 2009.
Our annual capital expenditure activity is summarized in the following table:
The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments except for contracted drilling services. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We currently expect to spend approximately $385.0 million for development and exploration projects in 2010, which will be funded primarily by cash flows from operating activities and cash on hand. Our operating cash flow and, therefore, our capital expenditures are highly dependent on oil and natural gas prices and, in particular, natural gas prices.
We do not have a specific acquisition budget for 2010 because the timing and size of acquisitions are unpredictable. Smaller acquisitions will generally be funded from operating cash flow. With respect to significant acquisitions, we intend to use borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.
We have a $850.0 million bank credit facility with Bank of Montreal, as the administrative agent. The bank credit facility is a five-year revolving credit commitment that matures on December 15, 2011. Indebtedness under the bank credit facility is secured by all of our and our subsidiaries assets and is guaranteed by all of our subsidiaries. The bank credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks estimates of the future net cash flows of our oil and natural gas properties. As of December 31, 2009 the borrowing base was $500.0 million, all of which was available. The borrowing base may be affected by the performance of our properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. Borrowings under the bank credit facility bear interest, based on the utilization of the borrowing base, at our option at either (1) LIBOR plus 2% to 2.75% or (2) the base rate (which is the higher of the administrative agents prime rate, the federal funds rate plus 0.5% or 30 day LIBOR plus 1.5%) plus 0.5% to 1.25%. A commitment fee of 0.5% is payable on the unused borrowing base. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends in excess of $40.0 million, limit the amount of consolidated debt that we may incur and limit our ability to make certain loans and investments. The only financial covenants are the maintenance of a ratio of current assets, including the availability under the bank credit facility, to current liabilities of at least one-to-one and maintenance of a minimum tangible net worth. We were in compliance with these covenants as of December 31, 2009.
We have $175.0 million of 67/8% senior notes outstanding which are due March 1, 2012. Interest is payable semiannually on each March 1 and September 1. We also have $300.0 million of 87/8% senior notes outstanding which are due October 15, 2017. Interest is payable semiannually on each October 15 and April 15. The senior notes are unsecured obligations and are guaranteed by all of our subsidiaries.
We believe that our cash flow from operations and available borrowings under our bank credit facility will be sufficient to fund our operations and future growth as contemplated under our current business plan. However, if our plans or assumptions change or if our assumptions prove to be inaccurate, we may be required to seek additional capital. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.
The following table summarizes our aggregate liabilities and commitments by year of maturity:
Future interest costs are based upon the effective interest rates of our outstanding senior notes.
We have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties. These payments are currently estimated to be incurred primarily after 2014. We record a separate liability for the fair value of these asset retirement obligations which totaled $6.6 million as of December 31, 2009.
Our federal income tax returns for the years ended December 31, 2006 and 2007 were recently under examination by the Internal Revenue Service, and these examinations have been closed with no additional tax liability. Our federal income tax returns for the years subsequent to December 31, 2007 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2004. We currently believe that our significant filing positions are highly certain and that all of our significant income tax filing positions and deductions would be sustained upon audit. Therefore, we have no significant reserves for uncertain tax positions. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.
At December 31, 2009, we had federal income tax net operating loss carryforwards of approximately $40.2 million. We have established a $23.0 million valuation allowance against a portion of the net operating loss carryforwards that we acquired in an acquisition due to a change in control limitation which will prevent us from fully realizing these carryforwards. The carryforwards expire from 2017 through 2021. The realization of these carryforwards depends on our ability to generate future taxable income in order to utilize these carryforwards.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.
Successful efforts accounting. We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities and we do not capitalize any of our general and administrative expenses.
Oil and natural gas reserve quantities. The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding years estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.
Impairment of oil and gas properties. We evaluate our properties on a field area basis for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the assets carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the propertys proved and risk adjusted probable oil and natural gas reserve estimates at the end of the period. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of the average first day of the month historical price for the year.
Asset retirement obligations. We have obligations to remove tangible equipment and facilities and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of any surface equipment used in production operations. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many
years in the future. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Stock-based compensation. We follow the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.
New accounting standards. In December 2007, the Financial Accounting Standards Board (the FASB) issued new accounting guidance, which we adopted January 1, 2009, requiring reporting entities to present noncontrolling minority interests as a component of stockholders equity instead of a liability and providing guidance on the accounting for transactions between an entity and noncontrolling interests.
In September 2008, the FASB issued new guidance which requires that unvested share-based payment awards containing nonforfeitable rights to dividends be considered participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. Earnings per share data for all periods presented have been adjusted retrospectively for the effects of this new guidance.
In December 2008, the SEC released the Final Rule, Modernization of Oil and Gas Reporting (the Final Rule) which revises oil and gas reserve estimations and reporting disclosures. This release permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The revised rules also limit the inclusion of proved undeveloped reserves to those that can be developed within a five year period unless specific circumstances justify a longer time. The Final Rule also allows companies to disclose their probable and possible oil and gas reserves. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its oil and gas reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (iii) report oil and gas reserves using an average price based upon the average first of the month prior twelve month period rather than a year end price. In October 2009 the SEC staff issued Staff Accounting Bulletin 113 to modify Topic 12, Oil and Gas Producing Activities, in order to conform financial reporting practices for public companies with the Final Rule. In January 2010 the FASB issued new accounting guidance to align the reserve calculation and disclosure requirements within generally accepted accounting principles with the Final Rule. All of these rule changes became effective on December 31, 2009. We have adopted these changes and conformed our reserve estimation and disclosure practices in accordance with the guidance contained in all of these releases.
In recent years, we have not entered into any material transactions with our officers or directors apart from the compensation they are provided for their services. We also have not entered into any business transactions with our significant stockholders or any other related parties.
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas,
the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2009, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $0.8 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $53.0 million.
We hedged approximately 10% of our price risks associated with our natural gas sales during 2009. Because our swap agreements were designated as hedge derivatives, changes in their fair value generally were reported as a component of accumulated other comprehensive loss until the related sales of production occurred. At that time, the realized hedge derivative gain or loss was transferred to oil and gas sales in our consolidated income statement. None of our derivative contracts had margin requirements or collateral provisions that could have required funding prior to the scheduled cash settlement date. We had no crude oil or natural gas derivative financial instruments outstanding as of December 31, 2009 and none of our oil or gas production is hedged in 2010 or thereafter.
At December 31, 2009, we had $470.8 million of long-term debt. Of this amount, $175.0 million bears interest at a fixed rate of 67/8% and $295.8 million bears interest at 83/8% (with an effective interest rate of 85/8%). The fair market value of our fixed rate debt as of December 31, 2009 was $479.9 million based on the market price of 102% of the face amount. At December 31, 2009, we had no amounts outstanding under our bank credit facility, which is subject to variable rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is tied to LIBOR or the corporate base rate, at our option. We had no interest rate derivatives outstanding during 2009 or at December 31, 2009.
Our consolidated financial statements are included on pages F-1 to F-28 of this report.
We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.
Our independent public accountants, Ernst & Young LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.
The audit committee of our board of directors is comprised of three directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.
Evaluation of disclosure controls and procedures. Our Chief Executive Officer and Chief Financial Officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the Exchange Act), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures are adequate and effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commissions rules and forms.
Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
The management of Comstock Resources, Inc. (the Company) is responsible for establishing and maintaining adequate internal control over financial reporting. The Companys internal control over financial reporting is a process designed under the supervision of the Companys Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Companys financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2009, management assessed the effectiveness of the Companys internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2009, based on those criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Companys internal control over financial reporting as of December 31, 2009. The report, which expresses unqualified opinions on the effectiveness of the Companys internal control over financial reporting as of December 31, 2009 is included below.
The Board of Directors and Stockholders
Comstock Resources, Inc.
We have audited Comstock Resources, Inc.s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Comstock Resources, Inc.s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Managements Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Comstock Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2008 and 2009, and the related consolidated statements of operations, stockholders equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009 and our report dated February 26, 2010 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
February 26, 2010
The information required by this item is incorporated herein by reference to Business Directors and Executive Officers in this Form 10-K and to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2009.
Code of Ethics. We have adopted a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees as required by New York Stock Exchange rules. We have also adopted a Code of Ethics for Senior Financial Officers that is applicable to our Chief Executive Officer and Senior Financial Officers. Both the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers may be found on our website at www.comstockresources.com. Both of these documents are also available, without charge, to any stockholder upon request to: Comstock Resources, Inc., Attn: Investor Relations, 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034, (972) 668-8800. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the definitive proxy statement for our 2010 annual meeting, which will be filed with the SEC within 120 days of December 31, 2009, for additional information regarding our corporate governance policies.
The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2009.
The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2009.
The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2009.
(a) Financial Statements:
1. The following consolidated financial statements and notes of Comstock Resources, Inc. are included on Pages F-2 to F-28 of this report:
2. All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.
The exhibits to this report required to be filed pursuant to Item 15 (c) are listed below.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
COMSTOCK RESOURCES, INC.
M. Jay Allison
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 26, 2010
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
COMSTOCK RESOURCES, INC.
The Board of Directors and Stockholders
Comstock Resources, Inc.
We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2008 and 2009, and the related consolidated statements of operations, stockholders equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Comstock Resources, Inc. and subsidiaries at December 31, 2008 and 2009, and the consolidated results of their operations and cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States.
As discussed in Note 1 to the consolidated financial statements, during the year ended December 31, 2009 the Company adopted new accounting standards relating to the manner in which basic and diluted earnings per share are calculated and the presentation of noncontrolling interests in consolidated subsidiaries, and changed its oil and gas reserves and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Comstock Resources, Inc.s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2010 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
February 26, 2010
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
As of December 31, 2008 and 2009
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
For the Years Ended December 31, 2007, 2008 and 2009
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2007, 2008 and 2009
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
For the Years Ended December 31, 2007, 2008 and 2009
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES