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CNX Gas 10-K 2006
Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K


(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the fiscal year ended December 31, 2005;

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number: 001-32723


CNX GAS CORPORATION

(Exact name of registrant as specified in its charter)


Delaware   20-3170639

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

4000 Brownsville Road

South Park, PA 15129-9545

(412) 854-6719

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)


Securities registered pursuant to Section 12(b) of the Act:

Title Of Each Class


 

Name of Each Exchange On Which Registered


Common Stock ($.01 par value)

  New York Stock Exchange

No securities are registered pursuant to Section 12(g) of the Act.


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

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

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  ¨    No  x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨

   Accelerated filer  ¨    Non-accelerated filer  x

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

The aggregate market value of voting stock held by nonaffiliates of the registrant as of January 31, 2006, based on the closing price of the common stock on the New York Stock Exchange on such date ($24.06 per share), was $669,040,149. For purposes of determining this amount, affiliates include directors and executive officers, who in the aggregate beneficially own 125,912 shares, and CONSOL Energy Inc., which beneficially owns 122,896,667 shares.

The number of shares outstanding of the registrant’s common stock as of January 31, 2006 is 150,833,334 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CNX Gas Corporation’s Proxy Statement for the Annual Meeting of Stockholders to be held on April 28, 2006, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III



Table of Contents

TABLE OF CONTENTS

 

          Page

     PART I     

Item 1.

  

Business

   4

Item 1A.

  

Risk Factors

   26

Item 2.

  

Properties

   34

Item 3.

  

Legal Proceedings

   34

Item 4.

  

Submission of Matters to a Vote of Security Holders

   35
    

Executive Officers of CNX Gas Corporation

   100
     PART II     

Item 5.

  

Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities

   36

Item 6.

  

Selected Financial Data

   38

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   41

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

   60

Item 8.

  

Financial Statements and Supplementary Data

   62

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

   98

Item 9A.

  

Controls and Procedures

   98

Item 9B.

  

Other Information

   99
     PART III     

Item 10.

  

Directors and Executive Officers of the Registrant

   100

Item 11.

  

Executive Compensation

   101

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management

   101

Item 13.

  

Certain Relationships and Related Transactions

   101

Item 14.

  

Principal Accounting Fees and Services

   101
     PART IV     

Item 15.

  

Exhibits and Financial Statement Schedules

   102

SIGNATURES

   103

 

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Table of Contents

FORWARD-LOOKING STATEMENTS

 

We are including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Annual Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

 

    our business strategy;

 

    our financial position;

 

    our cash flow and liquidity;

 

    declines in the prices we receive for our gas affecting our operating results and cash flow;

 

    uncertainties in estimating our gas reserves;

 

    replacing our gas reserves;

 

    uncertainties in exploring for and producing gas;

 

    our inability to obtain additional financing necessary in order to fund our operations, capital expenditures and to meet our other obligations;

 

    disruptions, capacity constraints in or other limitations on the pipeline systems which deliver our gas;

 

    competition in the gas industry;

 

    our inability to retain and attract key personnel;

 

    our joint venture arrangements;

 

    the effects of government regulation and permitting and other legal requirements;

 

    costs associated with perfecting title for gas rights in some of our properties;

 

    our need to use unproven technologies to extract coalbed methane in some properties;

 

    our relationships and arrangements with CONSOL Energy; and

 

    other factors discussed under “Risk Factors.”

 

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Table of Contents

PART I

 

ITEM 1. BUSINESS

 

General

 

We are engaged in the exploration, development and production of natural gas in the Appalachian Basin. We are also a leading developer of coalbed methane (CBM). CONSOL Energy Inc. (CONSOL Energy) owns 81.5% of our outstanding common stock. We have acquired all of CONSOL Energy’s rights associated with CBM from 4.5 billion tons of proved coal reserves owned or controlled by CONSOL Energy in Northern Appalachia, Central Appalachia, the Illinois Basin and other Western Basins. As of December 31, 2005, we had 1,130.4 Bcfe of net proved reserves, including our portion of equity affiliates, with a PV-10 value of $3,051.9 million and a standardized measure of discounted after tax future net cash flows attributable to our proved reserves of approximately $1,870.8 million. Our proved reserves are approximately 99% CBM and 49% proved developed. We believe that we are the second largest gas producer in the Appalachian Basin with net sales of 48.4 Bcf for the twelve months ended December 31, 2005. Our proved reserves are long-lived with a reserve life index of 22.5 years.

 

We have the development rights to approximately 704,000 net CBM acres throughout the Appalachian Basin. Presently, 97% of our proved reserves are located in Central Appalachia where we have the right to develop approximately 296,000 net CBM acres. As of December 31, 2005, we have developed 41% of our Central Appalachian CBM acreage. In Northern Appalachia, we have the rights to develop approximately 408,000 net CBM acres of which only 9% are currently classified as developed. Our undeveloped CBM acreage contains over 2,000 drilling locations. In addition to our CBM activities, we participate in two joint ventures that target conventional development opportunities on approximately 399,000 gross acres throughout the Appalachian Basin. Our conventional acreage position is 99% undeveloped and contains over 6,000 potential drilling locations.

 

We began extracting CBM in the early 1980s in order to reduce the gas content in the coal being mined by CONSOL Energy. We developed techniques to extract CBM from coal seams prior to mining in order to enhance the safety and efficiency of CONSOL Energy’s mining operations. As a result of our more than 20 years of experience with CBM extraction, we believe our management has developed industry-leading expertise in this type of gas production.

 

Except as otherwise noted or unless the context otherwise requires, (i) the information in this Annual Report gives effect to the contribution to CNX Gas of the CONSOL Energy gas business effective as of August 8, 2005, (ii) CNX Gas refers, with respect to any date prior to the effective date of that contribution, to the CONSOL Energy gas business and, with respect to any date on or subsequent to the effective date of the contribution, to CNX Gas and our subsidiaries, (iii) “CONSOL Energy” refers to CONSOL Energy Inc. and its subsidiaries other than CNX Gas and the companies which conducted CONSOL Energy’s gas business, and (iv) reserve and operating data are as of December 31, 2005, unless otherwise indicated. The estimates of our proved reserves as of December 31, 2004 and 2003 included in this Annual Report are based on reserve reports prepared by Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Services. The estimates of our proved reserves as of December 31, 2005 included in this Annual Report are based on a reserve report prepared by Schlumberger Data and Consulting Services. With the exception of “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and related financial statements, we discuss production, per unit revenue and per unit costs net of any royalty owners’ interest. We use the word “net” to indicate when a number does not include the royalty owners’ interest. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States of America, for the twelve months ended December 31, 2005, 2004 and 2003 is included in Note 19 to the Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.

 

4


Table of Contents

History of CNX Gas

 

We began extracting CBM from coal seams in Virginia in the early 1980s as part of CONSOL Energy’s operations. CBM was extracted from the Pocahontas #3 seam in order to reduce the amount of gas in the coal seam prior to mining to enhance safety. Typically, the gas was vented to the atmosphere.

 

In 1990, CONSOL Energy created a joint venture with Conoco Inc. (Conoco) to produce CBM that qualified for certain preferential tax treatment. Under an operating arrangement, CONSOL Energy operated gas wells and gathering facilities in which Conoco had an ownership interest. In 1993, CONSOL Energy acquired the assets of Island Creek Coal Company in Virginia, including an interest in CBM and gathering assets, from Occidental Petroleum (Occidental). The related gas assets acquired from Occidental were sold to MCN Energy Group Inc. (MCN) in 1995, although CONSOL Energy continued to operate gas wells in the area for MCN under an operating agreement.

 

Between 2000 and 2001, CONSOL Energy reacquired the assets of MCN and acquired the interests of our joint venture partner, Conoco, to consolidate our interest in Central Appalachia. This created the core of our business.

 

In 2002, Buchanan Generation, LLC, a joint venture between CONSOL Energy and Allegheny Energy Supply Company, LLC (Allegheny Energy), completed construction of an 88-megawatt electric generating peaking facility. The facility is located near our gas production complex in Virginia and operates on gas produced by our Central Appalachian gas operations.

 

Recent Events

 

CNX Gas Corporation’s registration statement on Form S-1 (SEC File No. 333-127483) was declared effective by the Securities and Exchange Commission (“SEC”) on January 18, 2006. On January 19, 2006, our common stock commenced trading on the New York Stock Exchange (“NYSE”) under the symbol “CXG.”

 

Our Relationship with CONSOL Energy

 

Prior to August 2005, we conducted business through various companies that were subsidiaries or joint ventures of CONSOL Energy, a public company traded on the New York Stock Exchange under the symbol CNX. Those companies include: CNX Gas Company LLC; Cardinal States Gathering Company (“CSGC”); Coalfield Pipeline Company; Knox Energy LLC; a joint venture with Kelly Oil and certain other entities; and Buchanan Generation, LLC. These are the companies primarily responsible for the exploration, production, transportation and sales of our gas, with the exception of Buchanan Generation LLC. Buchanan Generation LLC uses our gas to generate electricity from a generating facility located near our Virginia gas field. CONSOL Energy owns 81.5% of the outstanding common stock of CNX Gas.

 

As part of CONSOL Energy, our gas business was unique among gas producers because a substantial portion of our gas production was associated with mining activity in the same coal horizons from which gas could be extracted. For example, in 1999, more than 47% of our total gas production was attributable to mining activities. Currently, about 17% of our total gas production is attributable to mining activities, with the remainder of the gas produced not attributable to active mining activities, reflecting our investment in additional coalbed frac wells during the past five years.

 

We undertook the separation of our gas business from CONSOL Energy to achieve the following objectives:

 

    achieve a higher valuation for our business than we believe could be achieved if we remained part of CONSOL Energy;

 

    allow us to use our own capital and borrowing capability, rather than compete for capital with the mining business, to more rapidly expand gas production from our proven reserves and unproven acreages; and

 

    allow our key managers to focus solely on the growth and operation of CNX Gas.

 

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Table of Contents

The success of our operations substantially depends upon rights we received from CONSOL Energy. As a part of our separation from CONSOL Energy, CONSOL Energy transferred to CNX Gas various subsidiaries and joint venture interests as well as all of CONSOL Energy’s ownership or rights to CBM, natural gas, oil, and certain related surface rights. There were however, certain other property interests that were retained by CONSOL Energy and not conveyed to CNX Gas. These retained assets, which included, for example, assets associated with gas well plugging, had an aggregate book value of $6.6 million and are not material to the business and operations of CNX Gas. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with its coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements with CONSOL Energy under which they will provide us certain corporate staff services and coordinate our tax filings.

 

We have made every effort to preserve the synergies that exist between CONSOL Energy’s mining activities and our gas production activities. Additionally, the master cooperation and safety agreement between us and CONSOL Energy will ensure that we continue to have access to gob gas and gas produced from horizontal wells drilled from inside CONSOL Energy’s mines. These additional sources of gas enhance our overall recovery rates for CBM. Similar circumstances exist in the production of CBM in our Northern Appalachia area, where comparable mining techniques are employed.

 

Coordination with Mining Activities

 

Approximately 17% of our current gas production is produced as a consequence of coal extraction by CONSOL Energy (not including another approximately 16% of our production that is associated with previously mined areas). It is essential that gas liberated by the mining process be captured and removed from the mine in order to maintain a safe working environment in the mine. As a result, a portion of our gas extraction activity is determined based upon the needs of the related mining activity.

 

Through close cooperation and coordination between CNX Gas and CONSOL Energy, an annual drilling program is prepared that meets the needs of both companies. The master cooperation and safety agreement provides that each year, in consultation with CONSOL Energy, CNX Gas will outline its drilling plans to show: (i) the general area of drilling and the number of wells proposed to be drilled in the following calendar year, and (ii) the approximate location of all systems proposed to be installed by CNX Gas.

 

Other Assets

 

In addition to our production assets, we own certain mid-stream assets that are an integral part of our gas operations. Among the most important is our gathering system. Our operations in Central Appalachia built separate gathering systems to deliver gas to market. Each gathering system begins at the individual wellhead. Gas from wells is transported to market in each case by CSGC’s major gathering system. CSGC operates a 50-mile, 16-inch gathering system capable of transporting 100 mmcf of gas per day and a 30-mile, 20-inch gathering system capable of transporting 150 mmcf of gas per day. Each of these systems connects to a major interstate pipeline in West Virginia. The aggregate capacity of 250 mmcf per day in these systems is more than the current daily production from our Central Appalachia operations, allowing us to expand with economies of scale.

 

We also own various processing plants in Virginia and in Pennsylvania that remove contaminants from certain types of CBM gas in order to meet interstate pipeline standards. These plants allow us to sell gas that might otherwise be unsaleable.

 

Through a joint venture with Allegheny Energy, we own a 50% interest in an 88-megawatt, gas-fired electric generating facility in Virginia near our gas production facilities. This facility, which is used to meet peak load demands for electricity, uses the CBM that we produce. Because it is a peaking power facility, it does not operate at all times of the year, but the facility does provide a potential sales outlet for our gas of up to 22 mmcf per day.

 

6


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Currently all of our Central Appalachia production is transported to market on the Columbia interstate pipeline system. We expect to create transportation alternatives through certain transportation agreements with a second interstate pipeline operator, East Tennessee Natural Gas, LLC (ETNG), a subsidiary of Duke Energy. These agreements require the construction by ETNG of an approximately 32-mile lateral pipeline to our gas field in Virginia from ETNG’s major transportation pipeline to the south. Called Jewell Ridge, this proposed lateral pipeline currently is expected to be in service in the second half of 2006. In connection with the construction of the Jewell Ridge lateral, we will enter into a 15 year firm transportation agreement with ETNG at pre-determined fixed rates. We anticipate that the present value of our payments under this firm transportation agreement will be approximately $67 million. In addition to providing us with transportation flexibility, the Jewell Ridge Lateral will provide access for our product to alternate and growing natural gas markets in the southeastern United States.

 

Gas Operations

 

We produce CBM, which is gas that resides in coal seams. In the eastern United States, conventional natural gas fields typically are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put their capital at risk by searching for gas in commercially exploitable quantities at these depths. By contrast, gas in the coal seams that we drill or anticipate drilling is typically in formations less than 2,500 feet deep which are usually better defined than deeper formations. We believe that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations.

 

Nearly all of our gas production currently is from operations in Central Appalachia. In this region, we operated 1,862 net wells, 952 miles of gathering lines and various compression stations at December 31, 2005. Our Central Appalachia operations have the right to extract gas from approximately 296,000 net CBM acres. At December 31, 2005, we had 1,095.2 Bcfe of net proved reserves in Central Appalachia, of which 47.9% is developed. Our average daily net production for the month of December 2005 in this region was 130.9 mmcf per day.

 

We have been developing gas production in Northern Appalachia by gathering gob gas at CONSOL Energy mines in the area and by drilling vertical to horizontal wells in un-mined coal seams. In this region, we operated 133 wells at December 31, 2005 and our average daily net production for the month of December 2005 was approximately 7.6 mmcf per day. At December 31, 2005, we had 32.5 Bcf of net proved reserves in Northern Appalachia, of which approximately 78.4% is developed. We expect to expand production of gas in this area by drilling additional production wells into the coal seams that CONSOL Energy owns or controls.

 

We have also been developing gas production in the Tennessee area through a 50% joint venture. In this area, we operated 34.5 wells at December 31, 2005 and our portion of average daily net production for the month of December 2005 was approximately 0.2 mmcf per day. At December 31, 2005, our portion of proved net gas reserves for this area was 2.7 Bcfe, of which 100% were developed.

 

Areas of Operation

 

We operate in these principal areas of the Appalachian Basin:

 

Central Appalachia

 

We have the right to extract CBM in this region from approximately 296,000 net CBM acres, which contain most of the over 400 million tons of proved coal reserves owned or controlled by CONSOL Energy in Central Appalachia. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by CONSOL Energy in this region. This seam is generally found at depths of 2,000 feet and generally ranges from 3 to 6 feet thick. The gas content of this seam contains on average 400 to 600 cubic feet of gas per ton of coal in place. In addition, there

 

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are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively, this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to over 1,300 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

 

We coordinate some of our CBM extraction with the subsurface coal mining of CONSOL Energy. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam 5 to 10 years ahead of the planned mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a “frac well.” Presently, frac wells account for approximately 67% of our daily production.

 

Because some of our gas is produced in association with subsurface mining, we have a unique opportunity to evaluate the effectiveness of our fracture techniques. We can enter the coal mine and inspect the fracture pattern created in the seam as the mining process exposes more of the coal. As a result, we have had the opportunity to gain insight into the efficacy of our fracturing techniques that is not available in a conventional production scenario. We have used this knowledge to modify and improve the effectiveness of our fracturing techniques.

 

Eventually, subsurface mining activities will mine through the frac wells drilled in advance of the mine development plan. As the main coal seam is removed from an area (called a “panel”), a rubble zone (called “gob”) is created in the cavity created by the extraction of the coal. When the coal is removed, the rock above, which includes as many as 50 thinner, unminable coal seams, collapses into the void. These seams become extensively fractured and release substantial volumes of gas as they collapse. We drill vertical wells (called “gob wells”) into the gob to extract the additional gas that is released. Approximately 32% of our gas production comes in the form of gob gas (16% active gob and 16% sealed gob). CONSOL Energy pays for the drilling of our gob wells in most instances.

 

Recently, we began drilling long horizontal wellbores into the coal seam from within active mines. We strategically locate these horizontal wells within the pattern of existing frac wells to further accelerate the desorbtion of CBM from the coal seam. As of December 31, 2005, we have drilled 10 of these “in-mine” horizontal wells, some of which have been extended to lengths of 5,000 feet. The results from these wells are encouraging and suggest that a more efficient recovery of gas in place is possible ahead of mining operations. The production rates from frac wells have not been adversely impacted by the introduction of nearby horizontal wellbores in the coal seam. In fact, production at offsetting frac wells has actually increased due, we believe, to the further reduction in pressure within the coal seam caused by the horizontal wells. We intend to increase our use of the horizontal wells drilled within an active mine in our future development plans. In-mine horizontal wells account for about 1% of current daily production.

 

Northern Appalachia

 

We have the right to extract CBM in this region from approximately 408,000 net CBM acres, which contain most of the over 2.7 billion tons of proved coal reserves owned or controlled by CONSOL Energy in Northern Appalachia. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. We produce gas primarily from the Pittsburgh #8 seam which is the main coal seam mined by CONSOL Energy in this region. This seam is generally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas content of this seam is about 100 to 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30 feet. We have access to over 7,000 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

 

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Due to the significant geological differences between the Pittsburgh #8 seam in Northern Appalachia and the Pocahontas #3 seam in Central Appalachia, we have found that alternative extraction techniques are more effective than frac wells. Instead, we utilize a well design that relies on the application of vertical-to-horizontal drilling techniques that we developed. This well design includes a vertical wellbore that is intersected by a second well that has up to three horizontal lateral sections in the coal. Together, this well system facilitates extraction of CBM and water from the coal seam. The horizontal wellbores, extending 3,000 to 5,000 feet from the point of intersection with the vertical wellbore, expose large amounts of surface area of the coal seam allowing for the migration of water and CBM from the coal seam. This design creates up to 15,000 feet of total productive wellbore and are spaced in up to one square mile sections. The vertical well, equipped with a mechanical pump, provides a sump for water produced by the coal seam to collect and enables the collected water to be lifted to the surface for disposal. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region.

 

Tennessee

 

We are exploring for conventional natural gas in various formations at depths up to 6,500 feet with a joint venture partner and through a farm-out arrangement on approximately 208,000 gross leasehold acres in this region. At December 31, 2005, we had 2.7 Bcfe of proved reserves in this area. As of December 31, 2005, we have 40 gross wells that are operating. In total, we have an inventory of approximately 5,000 conventional gas drilling locations on this acreage, none of which are proved undeveloped locations.

 

Illinois and Other Western Basins

 

We have acquired all of CONSOL Energy’s rights associated with CBM from approximately over 1.4 billion tons of proved coal reserves owned or controlled by CONSOL Energy in these regions. We do not currently have any operations in these regions. We have not fully evaluated our ability to produce CBM in these regions and we may need to acquire additional rights from holders of real estate interests in order to obtain the rights needed to extract and produce CBM.

 

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The table below sets forth the states and counties in each of our principal operating areas where our properties reside. We have excluded the Illinois and Other Western Basins area from the table below, since we have not yet conducted our own operations in that area.

 

Central Appalachia Region

 

Kentucky

Breathitt

  

Floyd

   Johnson

Knott

  

Letcher

   Magoffin

Pike

         
Virginia

Bland

  

Buchanan

   Carroll

Culpeper

  

Dickenson

   Russell

Tazewell

  

Washington

   Wythe
West Virginia

Braxton

  

Clay

   Lewis

Logan

  

McDowell

   Mercer

Mingo

  

Nicholas

   Pocahontas

Raleigh

  

Randolph

   Upshur

Webster

  

Wyoming

    
Northern Appalachia Region
Maryland

Baltimore

         
Ohio

Athens

  

Belmont

   Carroll

Columbiana

  

Gallia

   Guernsey

Harrison

  

Highland

   Jefferson

Meigs

  

Monroe

   Morgan

Muskingum

  

Noble

   Perry

Vinton

  

Washington

    
Pennsylvania

Allegheny

  

Armstrong

   Beaver

Butler

  

Clearfield

   Fayette

Greene

  

Indiana

   Jefferson

Somerset

  

Washington

   Westmoreland
West Virginia

Barbour

  

Brooke

   Doddridge

Grant

  

Harrison

   Marion

Marshall

  

Monongalia

   Ohio

Taylor

  

Tucker

   Wetzel
Tennessee Region

Claiborne

  

Morgan

   Campbell

Scott

  

Roane

   Anderson
New York Region

Allegany

  

Steuben

    

 

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Summary of Appalachian Basin Properties as of December 31, 2005

 

     Central
Appalachia


   

Northern

Appalachia


    Tennessee

    New York

   Total

 

Estimated Net Proved Reserves (Bcfe)

   1,095.2     32.5     2.7     —      1,130.4  

Percent Developed (1)

   47.9 %   78.4 %   100 %   —      48.8 %

Net Producing Wells

   1,862     133     34.5     —      2,029.5  

No. of Potential Drill Sites Available

   2,900     722     5,053     —      8,675  
     Central
Appalachia


   

Northern

Appalachia


    Tennessee

    New York

   Total

 

Net Proved Developed CBM Acres

   120,720     36,311     —       —      157,031  

Net Proved Undeveloped CBM Acres

   33,320     5,760     —       —      39,080  

Net Unproved CBM Acres (2)

   141,960     365,760     —       —      507,720  
    

 

 

 
  

Total Net CBM Acres

   296,000     407,831     —       —      703,831  
    

 

 

 
  

Gross Proved Developed Conventional Acres

   2,780     —       2,680     —      5,460  

Gross Proved Undeveloped Conventional Acres

   —       —       —       —      —    

Gross Unproved Conventional Acres

   149,820     —       205,204     38,720    393,744  
    

 

 

 
  

Total Gross Conventional Acres

   152,600     —       207,884     38,720    399,204  
    

 

 

 
  


(1) We estimate the cost to fully develop our proved undeveloped reserves excluding abandonment is $361.1 million (non-discounted and in 2005 dollars).
(2) CBM extraction rights associated with CONSOL Energy owned or controlled coal.

 

Our inventory of conventional drilling sites was determined by dividing our acreage in each area by the well spacing generally used in that area. In Tennessee, wells are commonly drilled on 40 acre units and in Central Appalachia, wells are drilled on an average of 110 acre spacing. The inventory of CBM locations was determined in a detailed evaluation of our Northern Appalachia and Central Appalachia reserves by Schlumberger Data & Consulting Services. The total CBM drilling site inventory reflects the sum of 80-acre and 60-acre vertical development well locations, 40-acre infill well locations and 640-acre horizontal well locations identified in the study. The inventory of drilling sites excludes a number of potential locations in New York, Illinois and other Western Basins because we are not yet active in those areas.

 

We own all of the properties reflected in the table above by deed or by lease, other than the properties included in the production joint ventures described in the table below.

 

Summary of Production Partners and Joint Venture Interests as of December 31, 2005

 

Area


  Type

 

Production Partners
and Joint Venture
Interests


 

Acreage


  Working Interest

 

How Acquired


Central Appalachia

  Conventional   Columbia Natural Resources, LLC   152,600 Gross Conventional Acres  

50%

  Contributed by CONSOL Energy

Northern Appalachia

  N/A   None   N/A   N/A   N/A

Tennessee

  Conventional   New River Energy, LLC (1)   207,884 Gross Conventional Acres  

50%

  Acquired through lease jointly with New River Energy, LLC

New York

  Conventional   Kelly Oil and
Gas, Inc. Excelsior Exploration Corporation KWR Ventures, LLC Ceja Corporation
  38,720 Gross Conventional Acres  

25%

  By purchase of working interest

(1) New River Energy, LLC owns 50% of Knox Energy, LLC. We own the remaining 50%. A similar arrangement is in place with respect to Coalfield Pipeline Company which owns and operates the pipeline that gathers the Knox Energy, LLC gas for transportation to the sales pipeline.

 

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Recent Drilling Activity (net wells)

 

     2005

   2004

   2003

CBM (frac, gob, horizontal)

     240      228      256

Conventional

     —        12      24
    

  

  

Total Wells

     240      240      280
    

  

  

Completion %

     100      100      99

Total Capital Expenditures (in thousands)

   $ 110,752    $ 89,753    $ 83,869
    

  

  

 

Drilling

 

The total average daily gross rate of production controlled by us during the twelve months ended December 31, 2005, was 156.0 mmcf. During the twelve months ended December 31, 2005, December 31, 2004 and December 31, 2003, we drilled in the aggregate 225, 235 and 251 development wells, respectively, all of which were productive. The net number of wells for those periods was approximately 225, 228 and 244 wells, respectively. As of December 31, 2005, we have not had any dry development wells. The following table illustrates the wells referenced above by geographic region:

 

Development Wells

 

     Twelve Months Ended December 31,

     2005

   2004

   2003

     Gross

     Net  

   Gross

     Net  

   Gross

     Net  

Central Appalachia

   206    206    229    222    237    237

Northern Appalachia

   19    19    6    6    —      —  

Tennessee

   —      —      —      —      14    7
    
  
  
  
  
  

Total

   225    225    235    228    251    244
    
  
  
  
  
  

 

During the twelve months ended December 31, 2005, 2004 and 2003, we drilled in the aggregate 15, 17 and 52 exploratory wells, respectively. The net number of wells for those periods was 15, 12 and 36 respectively. The following table illustrates the exploratory wells by geographic region:

 

Exploratory Wells

 

     Gross

   Net

2005


   Producing

   Dry

   Still Eval.

   Producing

   Dry

   Still Eval.

Central Appalachia

   2    —      —      2    —      —  

Northern Appalachia

   13    —      —      13    —      —  

Tennessee

   —      —      —      —      —      —  
    
  
  
  
  
  
     15    —      —      15    —      —  
    
  
  
  
  
  
                               
     Gross

   Net

2004


   Producing

   Dry

   Still Eval.

   Producing

   Dry

   Still Eval.

Central Appalachia

   —      —      —      —      —      —  

Northern Appalachia

   7    —      —      7    —      —  

Tennessee

   10    —      —      5    —      —  
    
  
  
  
  
  
     17    —      —      12    —      —  
    
  
  
  
  
  

 

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     Gross

   Net

2003


   Producing

   Dry

   Still Eval.

   Producing

   Dry

   Still Eval.

Central Appalachia

   17    —      2        14    —      2

Northern Appalachia

   3    —      4    3    —      4

Tennessee

       16          3          7    8      1.5      3.5
    
  
  
  
  
  
     36    3    13    25    1.5    9.5
    
  
  
  
  
  

 

Summary of Other Operating Data

 

Production

 

The following table sets forth CNX Gas’ net sales volume produced for the periods indicated, including our portion of equity affiliates.

 

    

Twelve Months Ended

December 31,


     2005

   2004

   2003

Total Produced (mmcf)

   48,390    48,556    44,459

 

Average Sales Prices and Lifting Costs

 

The following table sets forth the average sales price, net of hedging transactions, and the average lifting cost, including our portion of equity interests, for all of our gas production for the periods indicated. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization.

 

     Twelve Months Ended
December 31,


       2005  

     2004  

     2003  

Average Gas Sales Price Including Effects of Financial
Settlements (per mcf)

   $ 6.08    $ 5.09    $ 4.14

Average Lifting Cost (per mcf)

   $ 0.57    $ 0.50    $ 0.48

 

Productive Wells and Acreage

 

The following table sets forth, at December 31, 2005, the number of CNX Gas’ producing wells, developed acreage and undeveloped acreage:

 

     Gross

   Net

Producing Wells

   2,073    2,030

Proved Developed Acreage

   162,491    159,761

Proved Undeveloped Acreage

   39,080    39,080

Unproven Acreage

   901,464    694,912

 

We drilled 225 development wells in the twelve months ended December 31, 2005, of which 51 wells were in process at December 31, 2005. Most of our development wells and acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied.

 

For 2006, the Board of Directors has approved a capital budget of $190 million. Plans include the drilling of 290 wells, including 215 frac wells in Central Appalachia, 23 vertical-to-horizontal wells in Northern Appalachia, and 47 conventional wells in our Knox Energy partnership in Tennessee. The well counts are exclusive of gob wells, which are expected to number 55. Additionally, CNX Gas plans to drill 21 frac wells that were carried over from the 2005 drilling program.

 

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Sales

 

CNX Gas enters into various physical gas sales transactions with both gas marketers and various other counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than pipeline outages related to maintenance, we have not failed to deliver quantities required under contract. CNX Gas has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These financial, as well as physical, hedges, represented approximately 70% of our produced gas sales volumes for the twelve months ended December 31, 2005 at an average price of $4.77 per mcf. As of December 31, 2005, we expect these transactions will cover approximately 31% of our estimated 2006 production.

 

We also have an operational balancing agreement with Columbia Gas Transmission Corporation (“Columbia”). This agreement is in accordance with the Council of Petroleum Accountants Societies’ definition of producer imbalances, whereby the operator controls the physical production and delivery of gas to a transporter. Contracted quantities of gas rarely equal physical deliveries. As the operator, CNX Gas is responsible for monitoring this imbalance and making adjustments to sales volumes as circumstances warrant. The imbalance agreement is managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken and paid for by the purchaser. The financial impacts of these imbalances were an $899 increase to expense and a $266 decrease to expense for the twelve months ended December 31, 2005 and 2004 respectively.

 

Due to the potential for curtailments on portions of the interruptible capacity allocated to us, CNX Gas purchased firm transportation capacity on the Columbia interstate pipeline. CNX Gas anticipates that there will be on-going curtailments of interruptible capacity as a result of the increased demand on the Columbia interstate pipeline, however this firm transportation capacity should offset a portion of the expected impacts from these curtailments. As of December 31, 2005, CNX Gas has secured firm transportation capacity to cover more than its 2006 hedged production. CNX Gas also participates in the short-term firm transportation markets to manage flows as market conditions dictate.

 

The hedging strategy and information regarding derivative instruments used are outlined in “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Qualitative and Quantitative Disclosures About Market Risk,” and in Note 17 of the notes to the consolidated annual financial statements included in Item 8 of Part II of this Annual Report.

 

Gathering

 

Our gas operations in Central Appalachia built separate gathering systems to deliver most of our gas to third party marketers. While each gathering system begins at the individual wellhead, gas from wells is transported to market in each case by CSGC’s major gathering system. CSGC is a wholly owned subsidiary which operates two major gathering trunklines. The first line is a 50-mile, 16-inch line that is capable of gathering 100 mmcf of gas per day. This line has processing and compression facilities and connects with Columbia’s interstate pipeline in Mingo County, West Virginia. The second line is a 30-mile, 20-inch line capable of gathering 150 mmcf of gas per day. This gathering line also connects with Columbia’s interstate pipeline in Wyoming County, West Virginia. This gathering system has a combined capacity of 250 mmcf per day compared with our 2005 annual average daily gross production of 148 mmcf. This excess capacity is vital to our plans to continue to grow our production volumes in Central Appalachia.

 

Transportation

 

The final transport of gas to market is handled by third party, interstate gas pipeline operators such as Columbia. In 2004, for the first time since we began producing gas, we experienced curtailments of pipeline capacity on Columbia’s line that transports most of our Central Appalachia gas to market. We experienced similar curtailments on KA-20 in 2005 and expect additional curtailments in 2006, primarily during April-July of

 

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2006. The growth of production in the Appalachian basin, expansion of the Cove Point liquid natural gas terminal downstream on the pipeline and summer season maintenance have resulted in constraints on the Columbia pipeline system.

 

We also intend to gain access to the ETNG pipeline, which is south of our Central Appalachia operations. ETNG has received the approval of the Federal Energy Regulatory Commission (“FERC”) for the construction of a 32-mile lateral pipeline, called Jewell Ridge Lateral, that will transport gas from our Central Appalachia operations to ETNG’s major transportation pipeline to the south. The FERC approval is subject to certain conditions, which ETNG is working to satisfy. Jewell Ridge Lateral is expected to be in service in the summer of 2006 and will provide us with an alternate transportation route to the northeast markets we currently serve as well as access to east coast markets.

 

Reserves

 

CNX Gas’ reserves are either owned or leased. Proved reserves are the estimated quantities 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. The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the SEC Rule 4.10(a) of Regulation S-X.

 

     Net Reserves (mmcfe)

     As of December 31,

     2005

   2004

   2003

    

Consolidated

Operations


  

Equity

Affiliates


  

Consolidated

Operations


  

Equity

Affiliates


  

Consolidated

Operations


  

Equity

Affiliates


Estimated proved developed reserves

   549,574    2,672    395,152    1,489    352,935    843

Estimated proved undeveloped reserves

   578,150    —      647,251    896    649,865    738
    
  
  
  
  
  

Total estimated proved developed and undeveloped reserves

   1,127,724    2,672    1,042,403    2,385    1,002,800    1,581
    
  
  
  
  
  

 

Discounted Future Net Cash Flows

 

The following table shows our net estimated proved developed and proved undeveloped reserves, our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:

 

    

Discounted Future Net Cash Flows

($ in thousands)


     As of December 31,

     2005

   2004

   2003

Future net cash flows

   $ 5,149,938    $ 2,872,571    $ 2,708,797

Total PV-10 measure of pre tax discounted future net cash flows (1)

   $ 3,051,866    $ 1,655,232    $ 1,556,866

Total standardized measure of after tax discounted future net cash flows

   $ 1,870,794    $ 1,029,538    $ 1,011,186

(1)

We calculate our PV-10 value in accordance with the following table. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes

 

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estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation to the most directly comparable GAAP measure—after tax discounted future net cash flows.

 

Reconciliation of PV-10 to Standardized Measure:

 

    

As of

December 31,


 
     2005

    2004

    2003

 

Future cash inflows

   $ 11,675,551     $ 6,337,257     $ 5,792,348  

Future Production Costs

     (2,852,033 )     (1,453,364 )     (1,314,691 )

Future Development Costs (including abandonments)

     (422,315 )     (265,540 )     (307,075 )
    


 


 


Future net cash flows

     8,401,203       4,618,353       4,170,582  

10% discount factor

     (5,349,337 )     (2,963,121 )     (2,613,716 )
    


 


 


PV-10 (Non-GAAP measure)

     3,051,866       1,655,232       1,556,866  
    


 


 


Undiscounted Income Taxes

     (3,251,265 )     (1,745,782 )     (1,461,785 )

10% discount factor

     2,070,193       1,120,088       916,105  
    


 


 


Discounted Income Taxes

     (1,181,072 )     (625,694 )     (545,680 )

Standardized GAAP measure

   $ 1,870,794     $ 1,029,538     $ 1,011,186  
    


 


 


 

Competition

 

Competition throughout the country is regionalized. We operate in the eastern United States. We believe that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition within our market is based primarily on cost and the proximity of gas fields to customers.

 

Subsidiaries and Joint Ventures

 

Prior to August 2005, we conducted business through various companies that were subsidiaries or joint ventures of CONSOL Energy. Those companies included three subsidiaries (CNX Gas Company LLC; Greene Energy—since merged into CNX Gas Company LLC; and CSGC); and four joint ventures (Coalfield Pipeline; Knox Energy; Buchanan Generation and an arrangement with Kelly Oil and various other entities). As part of our separation from CONSOL Energy, we have executed with CONSOL Energy a master separation agreement that transferred to us CONSOL Energy’s interests in these various subsidiaries and joint venture interests.

 

The following describes the material joint ventures in which we directly or indirectly hold interests.

 

Knox Energy LLC

 

This limited liability company was formed in Tennessee in 2001 and is owned 50% by CNX Gas Company LLC and 50% by New River Energy, LLC (New River Energy). Knox Energy is engaged in certain drilling operations in Tennessee, covering approximately 208,000 gross conventional acres in Tennessee. A management agreement, dated September 7, 2001, between CNX Gas Company LLC and New River Energy, governs the operation of the project wells. Under the management agreement, CNX Gas Company LLC, as operator, is responsible for drilling, completing and operating gas, CBM and oil wells. As operator, CNX Gas Company LLC has full control of the operation of the wells and is responsible for obtaining all necessary permits, building roads, finding suitable drilling rigs, and taking all other action as is customarily required to operate the wells. The management agreement does not have a defined term.

 

Knox Energy is also engaged in a project with Atlas America, Inc. (Atlas). In September 2004, Knox Energy entered into a three year drilling and operating agreement with Atlas which relates to certain natural gas

 

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and oil wells located in Anderson, Campbell, Claiborne, Morgan, Roane and Scott Counties, Tennessee. Atlas is the operator of the wells; Knox Energy, as the non-operator, is required to pay its proportionate share of drilling and other costs to Atlas. Knox Energy has the right to participate in a 50% working interest in each of the wells drilled after the initial ten permitted wells, under the agreement. Upon such participation, Knox Energy has the right to receive an overriding royalty payment equal to 1.5625%. Under the agreement, Knox Energy is prohibited from transferring its rights to explore or produce the natural gas or oil, other than methane gas from coalbeds or coal mines, from certain property to any party other than Atlas until June 30, 2007. Substantially all gas produced from the wells is transferred through the Coalfield Pipeline, pursuant to an agreement between Atlas and Coalfield Pipeline.

 

Coalfield Pipeline Company

 

Coalfield Pipeline is a Tennessee corporation, formed in 2001. Coalfield Pipeline is owned 50% by CNX Gas and 50% by New River Energy. Coalfield Pipeline compresses and, through its pipeline, transports natural gas from wells.

 

Coalfield Pipeline has an agreement with Atlas whereby it will transport all natural gas from the wells that Atlas drills pursuant to the Atlas agreement with Knox Energy. Also, Coalfield Pipeline has entered into gas purchase contracts with various third parties, including Ariana Energy, to transport all of their gas from their facilities.

 

Buchanan Generation, LLC

 

This Virginia limited liability company is owned 50% by CNX Gas and 50% by Allegheny Energy, to develop and operate a peaker power generation facility that is located in Buchanan County, Virginia. In 2002, the parties completed construction of Buchanan Generation’s LM 6000 combustion turbine 88-megawatt electric generating peaking facility.

 

This facility operates on gas produced by CNX Gas’ Central Appalachia operations. The generation facility is used to meet peak load demands for electricity by processing the CBM gas that CNX Gas produces. Because it is a peaking power facility, it does not operate at all times of the year, but the facility does provide a potential sales outlet for our gas of approximately 22 mmcf per day. Buchanan Generation’s facilities include the power plant used to generate electricity, as well as a water treatment site and facility, the generation facilities, and a gas extension easement. Allegheny Energy is the operator of the facility. Additionally, Buchanan Generation and Allegheny Energy entered into a marketing agreement, whereby Allegheny Energy will market for sale, on an exclusive basis, all electricity produced from the generation facilities.

 

Employee and Labor Relations

 

As of December 31, 2005, CNX Gas had 134 employees. None of our employees is represented by a union. We believe our relationship with our employees is satisfactory.

 

Regulations

 

The natural gas industry is subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, the treatment, storage and disposal of wastes, plant and wildlife protection, storage tanks, the reclamation of properties and plugging of wells after gas operations are completed, the discharge or release of materials into the environment, and the effects of gas well operations on groundwater quality and availability. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or our customers’ ability to use gas and may require us or our customers to change operations significantly or incur substantial costs.

 

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Table of Contents

Environmental Regulation of Gas Operations

 

Numerous governmental permits and approvals are required for gas operations. In order to obtain such permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas may have upon the environment and public and employee health and safety. Compliance with such permits and all other requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Moreover, failure to comply may result in the imposition of significant fines and penalties. Future legislation or regulations may increase and/or change the requirements for the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. This type of legislation and regulation, as well as future interpretations of existing laws, may result in substantial increases in equipment and operating costs to CNX Gas and delays, interruptions or a termination of operations, the extent of which cannot be predicted. Further, the imposition of new environmental regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste.

 

It is not possible to quantify the costs of compliance with all applicable federal and state environmental laws. While those costs have not been significant in the past, they could be significant in the future. CNX Gas had no significant environmental control facility expenditures for the twelve months ended 2005, 2004 and 2003. CNX Gas expects to incur $1.1 million related to water disposal wells in 2006. Any environmental costs are in addition to well closing costs; property restoration costs; and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits, to gather and submit required data to regulatory authorities, to characterize and dispose of wastes and effluents, and to maintain management operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has substantially increased the cost of gas production, but is, in general, a cost common to all domestic gas producers.

 

The magnitude of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to: the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites; the potential for new or changed laws and regulations; the development of new drilling, remediation, and detection technologies and environmental controls; and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, CNX Gas has incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances; environmental conditions; and natural resource damages related to properties and facilities currently or previously owned or operated as well as sites owned by third parties to which CNX Gas or our subsidiaries sent waste materials for disposal.

 

CNX Gas is subject to various generally-applicable federal environmental laws, including the following:

 

    the Clean Air Act;

 

    the Clean Water Act;

 

    the Toxic Substances Control Act;

 

    the Endangered Species Act:

 

    the Resource Conservation and Recovery Act; and

 

    the Emergency Planning and Community Right-to-Know Act;

 

as well as state laws of similar scope and substance in each state in which we operate.

 

These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations

 

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after construction. We have ongoing environmental management, compliance and permitting programs designed to assist in compliance with such environmental laws. We believe that we have obtained all required permits under federal and state environmental laws for our current gas operations. Further, we believe that we are in substantial compliance with such permits. However, if violations of permits, failure to obtain permits or other violations of federal or state environmental laws are discovered, we could incur significant liability: to correct such violations; to provide additional environmental controls; to obtain required permits; and to pay fines which may be imposed by governmental agencies. New permit requirements and other requirements imposed under federal and state environmental laws may cause us to incur significant additional costs that could adversely affect our operating results.

 

From time to time, we have been the subject of investigations, administrative proceedings, and litigation, by government agencies and third parties, relating to environmental matters. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us.

 

Federal Regulation of the Sale and Transportation of Gas

 

Various aspects of CNX Gas’ operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which gas could be sold. While “first sales” by producers of natural gas, and all sales of condensate and natural gas liquids can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the Natural Gas Policy Act in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

Commencing in April 1992, the Federal Energy Regulatory Commission issued Order Nos. 636, 636-A, 636-B, 636-C and 636-D, which require interstate pipelines to provide transportation services separate, or “unbundled,” from the pipelines’ sales of gas. Also, Order No. 636 requires pipeline operators to provide open access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Although Order No. 636 does not directly regulate CNX Gas’ production activities, the Federal Energy Regulatory Commission has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry.

 

The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the Federal Energy Regulatory Commission continues to review and modify its open access regulations. In particular, the Federal Energy Regulatory Commission has reviewed its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, the Federal Energy Regulatory Commission issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to “fine tune” the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include:

 

(1) waiving the price ceiling for short-term capacity release transactions until September 30, 2002 (which was reversed pursuant to an order on remand issued by the Federal Energy Regulatory Commission on October 31, 2002);

 

(2) permitting value-oriented peak/off-peak rates to better allocate revenue responsibility between short-term and long-term markets;

 

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(3) permitting term-differentiated rates, in order to better allocate risks between shippers and the pipeline;

 

(4) revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties;

 

(5) retaining the right of first refusal and the five year matching cap for long-term shippers at maximum rates, but significantly narrowing the right of first refusal for customers that the Federal Energy Regulatory Commission does not deem to be captive; and

 

(6) adopting new web site reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments.

 

The new reporting requirements became effective on September 1, 2000. The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CNX Gas’ gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CNX Gas does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.

 

CNX Gas owns certain natural gas pipeline facilities that it believes meet the traditional tests which the Federal Energy Regulatory Commission has used to establish a pipeline’s status as a gatherer not subject to the Federal Energy Regulatory Commission jurisdiction.

 

Additional proposals and proceedings that might affect the gas industry are pending before Congress, the Federal Energy Regulatory Commission, the Minerals Management Service, state commissions and the courts. CNX Gas cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, CNX Gas does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of CNX Gas or its subsidiaries. No material portion of CNX Gas’ business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

 

State Regulation of Gas Operations—United States

 

CNX Gas’ operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. CNX Gas’ operations are also subject to various conservation laws and regulations. These include regulations that affect the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of gas properties. In addition, state conservation laws establish maximum rates of production from gas wells,

 

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and generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. These regulatory burdens may affect profitability, and CNX Gas is unable to predict the future cost or impact of complying with such regulations.

 

Ownership of Mineral Rights

 

The majority of our drilling operations are conducted on properties related to CONSOL Energy’s coal holdings. The typical arrangement is for CONSOL Energy to obtain ownership or leasehold rights in the properties and then assign to us the CBM and other gas rights. Consequently, our existing rights are often dependent on CONSOL Energy having obtained valid title to its properties.

 

CONSOL Energy’s past practice has been to acquire ownership or leasehold rights to its coal properties prior to conducting its coal mining operations. Given CONSOL Energy’s long history as a coal producer we believe it has a well developed ownership position relating to its coal holdings. Although CONSOL Energy generally attempts to obtain ownership or leasehold rights to CBM and/or conventional gas related to its coal holdings, its ownership position relating to these property estates is less developed. As is customary in the coal and gas industry, a summary review of the title to coal, CBM and other gas rights is made on properties at the time of the acquisition of the other rights in the properties. Prior to the commencement of gas drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence our drilling operations on a property until we have cured any material title defects on such property. We completed title work on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the gas industry. Our natural gas properties are subject to customary royalty and other interests and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

 

The following summary sets forth an analysis of provisions of Pennsylvania, Virginia and West Virginia law relating to the ownership of CBM. These summaries do not purport to be complete and are qualified in their entirety by reference to the provisions of applicable law and rights and the laws relating to conventional natural gas resources may differ materially from the rights related to CBM. These summaries are based on current law as of the date of this Annual Report.

 

Pennsylvania

 

In Pennsylvania, CBM that remains inside the coal seam is generally the property of the owner of that coal seam where the gas is located. CBM can be sold in place or leased by the coal owner to another party such as a producer who then would have the right to extract the gas from the coal seam under the terms of the agreement with the coal owner. Once the gas migrates from the coal into other strata, the coal owner no longer has clear title to that migrated gas. As a result, in certain circumstances in Pennsylvania (e.g., in a gob or mine void), we may be required to obtain other property interests (beyond ownership or leasehold interest in the coal rights or CBM) in order to extract gas that is no longer located in the coal seam.

 

Virginia

 

The vast majority of CBM we produce as well as our proven reserves are in Virginia, which has been the focus of our developmental efforts to date. In Virginia, the Virginia Supreme Court has stated that the grant of coal rights only does not include rights to CBM absent an express grant of CBM, natural gases, or minerals in general. The situation may be different if there is any expression in the severance deed indicating more than mere coal is conveyed. This Court has also found that the owner of the CBM did not have the right to fracture the coal

 

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in order to retrieve the CBM and that the coal operator had the right to ventilate the CBM in the course of mining. In Virginia, we believe that we control the relevant property rights in order to capture gas from the vast majority of our producing properties.

 

In addition, Virginia has established the Virginia Gas and Oil Board and a procedure for the development of CBM by an operator in those instances where the owner of the CBM has not leased it to the operator or in situations where there are conflicting claims of ownership of the CBM. The general practice is to force pool both the coal owner and the gas owner. In those instances, any royalties otherwise payable are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The Virginia Gas and Oil Board does not make ownership decisions.

 

West Virginia

 

In West Virginia, its Supreme Court has held that, in a conventional oil and gas lease executed prior to the inception of widespread public knowledge regarding CBM operations, the oil and gas lessee did not acquire the right to produce CBM. As of December 31, 2005, the West Virginia courts have not clarified who owns CBM in West Virginia. Therefore, the ownership of CBM is an open question in West Virginia. At the current locations where we produce CBM in West Virginia, we were able to acquire ownership of the CBM by acquiring additional rights to CBM from the owners of all of the possibly relevant real estate interest holders.

 

West Virginia has enacted a law, the Coalbed Methane Well and Units Act (the “West Virginia Act”), regulating the commercial recovery and marketing of CBM. Although the West Virginia Act does not specify who owns, or has the right to exploit, CBM in West Virginia and instead refers ownership disputes to judicial resolution, it contains provisions similar to Virginia’s forced pooling law. Under the pooling provisions of the West Virginia Act, an applicant who proposes to drill can prosecute an administrative proceeding with the West Virginia coalbed methane review board to obtain authority to produce CBM from pooled acreage. Owners and claimants of CBM interests who have not consented to the drilling are afforded certain elective forms of participation in the drilling (e.g., royalty or owner) but their consent is not required to obtain a pooling order authorizing the production of CBM by the operator within the boundaries of the drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that title to coal and title to natural gas are vested in different persons, the operator of a CBM well permitted, drilled and completed under color of title to the CBM from either the coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass relating to the drilling and commercial production of CBM from that well.

 

We anticipate in future years to more actively explore and develop Northern Appalachian CBM in Pennsylvania and West Virginia. As indicated, we may need or desire to acquire additional rights from other holders of real estate interests, including acquiring rights from other real estate interest holders in West Virginia if the law at that time continues to lack clarity on ownership rights to CBM in West Virginia. As we explore and develop this other acreage where CONSOL Energy has coal rights and has leased/conveyed to us CONSOL Energy’s rights to CBM, we expect in accordance with our existing procedures to have a title examination performed of CONSOL Energy’s rights to CBM. If we believe we need to obtain additional rights from the holders of other real estate interests, we expect to develop a methodology as part of deciding the feasibility of developing a particular tract to evaluate the ability to locate and negotiate a royalty arrangement with those other holders or in the case of West Virginia to use force pooling under the West Virginia Act.

 

Other States

 

We have been transferred rights to extract CBM held by CONSOL Energy in other states where it has coal reserves, including the states which comprise the Illinois Basin and certain other Western Basins. We have not examined the rights we have received in those states or applicable state law. The ownership of CBM in these other states may also be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate interests to extract and produce CBM in these other states.

 

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GLOSSARY OF NATURAL GAS AND COAL TERMS

 

The following is a description of the meanings of some of the oil and gas industry terms used in this Annual Report.

 

Appalachian Basin. A mountainous region in the eastern United States, running from northern Alabama to New York, and including parts of Georgia, South Carolina, North Carolina, Tennessee, Kentucky, Pennsylvania, Virginia, and all of West Virginia.

 

Bcf. Billion cubic feet of natural gas.

 

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

 

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 

CBM. Coalbed methane.

 

Central Appalachia. As used in this Annual Report, Central Appalachia includes Virginia and southern West Virginia.

 

Coal Seam. A single layer or stratum of coal.

 

Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

Development well. A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

 

Dry hole. 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.

 

Exploitation. Ordinarily considered to be a form of development within a known reservoir.

 

Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

 

Farm-in or farm-out. An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

 

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Frac well. A vertical well drilled in advance of mining and producing from zones artificially fractured or stimulated and which is capable of producing natural gas.

 

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Gathering system. Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

 

Gob. The de-stressed zone associated with any full seam extraction of coal that extends above and below the mined out coal seam, and which may be sealed or unsealed.

 

Gob gas. Gas produced from (a) a well drilled in advance of mining or after mining for the purpose of extracting natural gas from the gob or (b) a frac well that is recompleted for the purpose of extracting natural gas from the gob.

 

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

 

Longwall mining. An automated form of underground coal mining characterized by high recovery and extraction rates. A high-powered cutting machine is passed across the exposed face of coal, shearing away broken coal, which is continuously hauled away by a floor-level conveyor system. Longwall mining extracts all machine-minable coal between the floor and ceiling within a contiguous block of coal, known as a panel, leaving no support pillars within the panel area. Longwall mining is done under movable roof supports that are advanced as the bed is cut. The roof in the mined-out area is allowed to fall as the mining advances.

 

mcf. Thousand cubic feet of natural gas.

 

mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

MMBtu. Million British thermal units.

 

mmcf. Million cubic feet of natural gas.

 

mmcfe. Million cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

 

Northern Appalachia. As used in this Annual Report, Northern Appalachia includes southwestern Pennsylvania and northern West Virginia.

 

NYMEX. The New York Mercantile Exchange.

 

Panel. A contiguous block of coal that generally comprises one operating unit.

 

Pay zone. The section of rock, from which gas is expected to be produced in commercial quantities.

 

PV-10 or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of income taxes. The estimated future net revenues are discounted at an annual rate of 10% in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

 

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

 

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

 

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

 

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

 

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

 

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

Shut in. Stopping an oil or gas well from producing.

 

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

 

Vertical-to-horizontal well. A well in which the drilling from the surface initially proceeds vertically until reaching a particular depth, at which point, the drill bit is turned to proceed at up to 90 degrees from vertical in order to follow a particular stratum or pay zone.

 

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

 

EXECUTIVE OFFICERS OF THE COMPANY

 

Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Officers of the Registrant” (included herein pursuant to Item 401(b) of Regulation S-K).

 

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ITEM 1A. RISK FACTORS

 

In addition to the trends and uncertainties described in Item I of this Annual Report and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” CNX Gas is subject to the trends and uncertainties set forth below.

 

Natural gas and oil prices are volatile, and a decline in natural gas and oil prices would significantly affect our financial results and impede our growth.

 

Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and oil. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices have a significant impact on the value of our reserves and on our cash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. However, in 2006 we expect to be significantly less hedged than we have been in the past. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

    the domestic and foreign supply of natural gas and oil;

 

    the price of foreign imports;

 

    overall domestic and global economic conditions;

 

    the consumption pattern of industrial consumers, electricity generators and residential users;

 

    weather conditions;

 

    technological advances affecting energy consumption;

 

    domestic and foreign governmental regulations;

 

    proximity and capacity of oil and gas pipelines and other transportation facilities; and

 

    the price and availability of alternative fuels.

 

Many of these factors may be beyond our control. Because approximately 100% of our estimated proved reserves as of December 31, 2005 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Earlier in this decade, natural gas prices were much lower than they are today. Lower natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

 

We face uncertainties in estimating proven recoverable gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.

 

Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. We have in the past retained the services of independent petroleum

 

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engineers to prepare reports of our proved reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing, and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.

 

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:

 

    geological conditions;

 

    changes in governmental regulations and taxation;

 

    assumptions governing future prices;

 

    the amount and timing of actual production;

 

    future operating costs; and

 

    capital costs of drilling new wells.

 

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. In addition, if natural gas prices decline by $0.10 per mcf, then the pre-tax PV-10 of our proved reserves as of December 31, 2005 would decrease from $3,051.9 million to $3,015.2 million.

 

Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.

 

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2005, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

 

Our exploration and development activities may not be commercially successful.

 

The exploration for and production of gas involves numerous risks. The cost of drilling, completing and operating wells for CBM or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

 

    unexpected drilling conditions;

 

    title problems;

 

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    pressure or irregularities in geologic formations;

 

    equipment failures or repairs;

 

    fires or other accidents;

 

    adverse weather conditions;

 

    reductions in natural gas and oil prices;

 

    pipeline ruptures; and

 

    unavailability or high cost of drilling rigs, other field services and equipment.

 

Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues.

 

Our business depends on transportation facilities owned by others. Disruption of, capacity constraints in, or proximity to pipeline systems could limit our sales and increase costs of producing our gas.

 

We transport our gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, and our transportation costs could increase, reducing our profitability. If we cannot access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. In the current year, we have had to shut-in production due to shipping capacity limitations on Columbia’s KA-20 line that transports most of our Virginia gas to market and to compete with other producers for a portion of the pipeline capacity by purchasing firm transportation capacity that added to our cost. Although we have reached an agreement with ETNG, to gain access to its pipeline, we may not be able to successfully gain access to that pipeline. If our sales are reduced because of transportation constraints, our revenues will be reduced, which will also increase our costs. If we are not successful with our bid for transportation capacity and we do not have the ability to store gas, we may have to reduce production.

 

We operate in a highly competitive environment and many of our competitors have greater resources than we do.

 

The gas industry is intensely competitive and we compete with companies from various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, its operating results and financial position may be adversely affected. For example, one of our competitive strengths is as a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive strength in that area.

 

In addition, larger companies may be able to pay more to acquire new properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

 

The coal beds from which we produce methane gas frequently contain water that may hamper our ability to produce gas in commercial quantities.

 

Coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may affect our profitability.

 

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We may be unable to retain our existing senior management team and/or our key personnel who have expertise in coalbed methane extraction and our failure to continue to attract qualified new personnel could adversely affect our business.

 

Our business requires disciplined execution at all levels of our organization to ensure that we continually develop our reserves and produce gas at profitable levels. This execution requires an experienced and talented management and production team. If we were to lose the benefit of the experience, efforts and abilities of any of our key executives and/or the members of our team that have developed substantial expertise in coalbed methane extraction, such as Nicholas DeIuliis, our Chief Executive Officer and President and Ronald Smith, our Executive Vice President and Chief Operating Officer, our business could be materially adversely affected. No employment agreements have been or are expected to be executed with these key executives. Furthermore, our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified managerial and production personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

 

We are party to, and may in the future become party to, joint ventures and other arrangements with third parties that may impact our operations and our financial performance.

 

We have entered into several joint venture arrangements with third parties. For example, we are involved with third parties in Knox Energy (exploration and production), Coalfield Pipeline Company (Coalfield Pipeline) (gas pipeline) and Buchanan Generation, LLC (Buchanan Generation) (peaker electrical power generation plant) and in a participation agreement with Kelly Oil & Gas, Inc. (Kelly Oil), Excelsior Exploration Corporation, KWR Ventures, LLC and Ceja Corporation (exploration and production). We may also enter into other arrangements like these in the future. For example, we have an agreement with ETNG, whereby ETNG would construct and transport gas on a pipeline running from its main trunk line up to our Virginia operations. In many instances we depend on these third parties for elements of these arrangements that are important to the success of the joint venture and the performance of these third parties’ obligations or their ability to meet their obligations under these arrangements are outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements may be adversely affected. If our current or future joint venture partners are unable to meet their obligations we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights that may cause disputes among our joint venture parties and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, these joint ventures and/or our ability to enter into future joint ventures.

 

Government laws, regulations and other legal requirements relating to protection of the environment, health and safety matters and others that govern our and CONSOL Energy’s businesses increase our costs and may restrict our operations.

 

We and our principal stockholder, CONSOL Energy, are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, control of surface subsidence from underground mining and work practices related to employee health and safety. Complying with these requirements, including the terms of our and CONSOL Energy’s permits, has had, and will continue to have, a significant effect on our respective costs of operations and competitive position. In addition, we could incur substantial costs, including clean-up costs, fines and civil or criminal sanctions and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a result of violations of or liabilities under environmental and health and safety laws. Moreover, given our relationship with CONSOL Energy, its compliance with these laws and regulations could impact our ability to effectively produce gas from our wells.

 

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Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.

 

We must obtain governmental permits and approvals for drilling operations, which can be a costly and time consuming process and result in restrictions on our operations.

 

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of gas may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

 

We may incur additional costs to produce gas because our chain of title work for gas rights in some of our properties may be inadequate or incomplete.

 

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. These properties were acquired by our principal stockholder primarily for the coal rights, and, in many cases were acquired years ago. While chain of title work for the coal estate was generally fully developed, in many cases, the gas estate title work is less robust. Our practice is to review gas estate title work when we consider exploratory or production drilling and to obtain any additional rights needed to perfect our ownership for production purposes of the gas estate. In addition, the steps needed to perfect our ownership varies from state to state and some states permit us to produce the gas without perfected ownership under forced pooling arrangements while other states do not permit this. As a result, we may have to incur title costs and pay royalties to produce gas on acreage that we control and these costs may be material and vary depending upon the state in which we operate. In addition, although CONSOL Energy has conveyed to us all of their right to extract and produce CBM from locations where they possess rights to coal, in some cases CONSOL Energy may not possess these rights. If we are unable in such cases to obtain those rights from their owners, we will not enjoy the rights to develop the CBM with CONSOL Energy’s mining of coal, as provided in the master cooperation and safety agreement. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves. For example, we have substantial acreage in West Virginia for which we have not reviewed the title to determine what, if any, additional rights would be needed to produce CBM from those locations or the feasibility of obtaining those rights.

 

In addition to acquiring these property right assets on an “as is where is basis”, we have assumed all of the liabilities related to these assets, even if those liabilities were as a result of activities occurring prior to CONSOL Energy’s transfer of those assets to us. Our assumption of these liabilities is subject to the following allocation: we will be responsible for the first $10 million of aggregate unknown liabilities; CONSOL Energy will be responsible for the next $40 million of aggregate unknown liabilities; and we will be responsible for any additional unknown liabilities over $50 million. We will also be responsible for any unknown liabilities which were not asserted in writing by August 7, 2010.

 

We need to use unproven technologies to extract coalbed methane on some of our properties.

 

Our ability to extract gas in coal seams with lower gas content per ton of coal such as the Pittsburgh #8 seam requires the use of advanced technologies that are still being developed and tested. Horizontal drilling is the

 

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advanced technology currently being used. This technique, applied in coal, requires a well design that promotes simultaneous production of water and methane without significant back-pressure, a well that can be subsequently mined through without jeopardizing mine-safety and a well that will ensure well bore integrity throughout its projected life.

 

Other persons could have ownership rights in our advanced extraction techniques which could force us to cease using those techniques or pay royalties.

 

Although we believe that we hold sufficient rights to all of our advanced extraction techniques, other persons could contest our rights and claim ownership of one or more of our advanced techniques for extracting CBM. For example, a third party recently asserted that several of our drilling techniques infringed several patents held by that person. A successful challenge to one or more of our advanced extraction techniques could adversely impact our financial performance and results of operation. We might have to pay a royalty which would increase our production costs or cease using that technique which could raise our production costs or decrease our production of CBM. In addition, we could incur substantial costs in defending patent infringement claims, obtaining patent licenses, engaging in interference and opposition proceedings or other challenges to our patent rights or intellectual property rights made by third parties or in bringing such proceedings.

 

Currently the vast majority of our producing properties are located in two counties in southwestern Virginia, making us vulnerable to risks associated with having our production concentrated in one area.

 

The vast majority of our producing properties are geographically concentrated in two counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.

 

We do not insure against all potential operating risks. We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas operations.

 

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. As part of our separation from CONSOL Energy, we assumed all of the liabilities related to the gas assets and operations which were transferred to us, including liabilities resulting from operations prior to the effective date of the separation. Arrangements with CONSOL Energy significantly limit our seeking indemnification from CONSOL Energy for unknown liabilities that we have assumed. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.

 

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Risks Relating to Our Relationship with CONSOL Energy

 

Our principal stockholder, CONSOL Energy, is in a position to affect our ongoing operations, corporate transactions and other matters, and some of our directors also serve on its board of directors and/or are employees of CONSOL Energy, creating potential conflicts of interest.

 

Our principal stockholder, CONSOL Energy, owns 81.5% of our outstanding shares of common stock. As a result, CONSOL Energy will be able to determine the outcome of all corporate actions requiring stockholder approval. For example, CONSOL Energy will continue to control decisions with respect to:

 

    the election and removal of directors;

 

    mergers or other business combinations involving us;

 

    future issuances of our common stock or other securities; and

 

    amendments to our certificate of incorporation and bylaws.

 

Any exercise by CONSOL Energy of its control rights may be in its own best interest which may not be in the best interest of our other stockholders and our company. CONSOL Energy’s ability to control our company may also make investing in our stock less attractive. These factors in turn may have an adverse effect on the price of our common stock.

 

In addition, some of our directors serve as directors or officers of CONSOL Energy, and/or own CONSOL Energy stock, stock units or options to purchase CONSOL Energy stock, or they may be entitled to participate in the CONSOL Energy compensation plans. CONSOL Energy provides, and may in the future provide additional, cash- and equity-based compensation to employees or others based on CONSOL Energy’s performance. These arrangements and ownership interests or cash- or equity-based awards could create, or appear to create, potential conflicts of interest when directors or executive officers who own CONSOL Energy stock or stock options or who participate in the CONSOL Energy equity plan arrangements are faced with decisions that could have different implications for CONSOL Energy than they do for us. These potential conflicts of interest may not be resolved in our favor.

 

Potential conflicts may arise between us and CONSOL Energy that may not be resolved in our favor.

 

The relationship between CONSOL Energy and us may give rise to conflicts of interest with respect to, among other things, transactions and agreements among CONSOL Energy and us, issuances of additional voting securities and the election of directors. When the interests of CONSOL Energy diverge from our interests, CONSOL Energy may exercise its substantial influence and control over us in favor of its own interests over our interests. Our certificate of incorporation and the master cooperation and safety agreement entitle CONSOL Energy to various corporate opportunities which might otherwise have belonged to us and relieve CONSOL Energy and its directors, officers and employees from owing us fiduciary duties with respect to such opportunities.

 

Our intercompany agreements with CONSOL Energy are not the result of arm’s-length negotiations.

 

We have entered into agreements with CONSOL Energy which govern various transactions between us and our ongoing relationship, including registration rights, tax sharing and indemnification. All of these agreements were entered into while we were a wholly-owned subsidiary of CONSOL Energy, and were negotiated in the overall context of CONSOL Energy creating CNX Gas. As a result, these agreements were not negotiated at arm’s-length. Accordingly, certain rights of CONSOL Energy, particularly the rights relating to the number of demand and piggy-back registration rights that CONSOL Energy will have, the assumption by us of the registration expenses related to the exercise of these rights, our indemnification of CONSOL Energy for certain liabilities under these agreements, our payment of taxes and the retention of tax attributes may be more favorable

 

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to CONSOL Energy than if the agreements had been the subject of independent negotiation. We and CONSOL Energy and its other affiliates may enter into other material transactions and agreements from time to time in the future which also may not be deemed to be independently negotiated.

 

Our agreements with CONSOL Energy may limit our ability to obtain capital, make acquisitions or effect other business combinations.

 

Our business strategy anticipates future acquisitions of natural gas and oil properties and companies. Any acquisition that we undertake would be subject to the limitations and restrictions set forth in our agreements with CONSOL Energy and could be subject to our ability to access capital from outside sources on acceptable terms through the issuance of our common stock or other securities.

 

Our prior and continuing relationship with CONSOL Energy exposes us to risks attributable to CONSOL Energy’s businesses.

 

We and CONSOL Energy are obligated to indemnify each other for certain matters as set forth in our agreements with CONSOL Energy. As a result, any claims made against us that are properly attributable to CONSOL Energy (or conversely, claims against CONSOL Energy that are properly attributable to us) in accordance with these arrangements could require us or CONSOL Energy to exercise our respective rights under the master separation agreement and the master cooperation and safety agreement. In addition, we have an agreement with CONSOL Energy that we will refrain from taking certain actions that would result in CONSOL Energy being in default under its debt instruments. Those debt instruments currently contain covenants that would be breached if we borrow from a third party unless we contemporaneously guaranteed indebtedness of CONSOL Energy under those debt instruments. In addition, those debt instruments contain covenants that would be breached by our granting liens on certain assets unless we contemporaneously grant a pari passu lien securing the indebtedness of CONSOL Energy under those debt instruments. In connection with our obtaining an unsecured credit facility with a group of commercial lenders, we recently guaranteed CONSOL Energy’s $250 million 7.875% notes due March 1, 2012. We are exposed to the risk that, in these circumstances, CONSOL Energy cannot, or will not, make the required payment or in turn that we are required to make a required payment to CONSOL Energy. If this were to occur, our business and financial performance could be adversely affected.

 

CONSOL Energy Inc. has advised us that as of the date of this Annual Report, CONSOL Energy has no plan or intention regarding its shares of our common stock and if CONSOL Energy were to make a distribution or otherwise dispose of its remaining ownership interest in us, our common stock price could be adversely affected.

 

Unless and until CONSOL Energy distributes to its stockholders, either in a tax-free spin-off or one or more special dividends, or sells the controlling amount of our common stock it owns, we will face the risks discussed in this Annual Report relating to CONSOL Energy’s control of us and potential conflicts of interest between CONSOL Energy and us. CONSOL Energy may elect not to make such a distribution or sale or it could at any time make that distribution or sale. Additionally, the market price of our common stock could decline as a result of market sales by CONSOL Energy, a distribution of our common stock to CONSOL Energy’s stockholders or the perception that such sales or distributions will occur. These sales or distributions also might make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. Future sales of our common stock could impact the price at which the shares purchased or acquired by our investors may be sold in the future.

 

We must coordinate some of our gas production activities with coal mining activities in the same area, which could adversely affect our financial condition or operations.

 

In many places where we extract CBM, the coal estate is dominant. Where our principal stockholder conducts mining activity, CONSOL Energy could exercise its rights to determine when and where certain drilling

 

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can take place in order to ensure the safety of the mine or to protect the mineability of the coal. For example, if CONSOL Energy is required to cease mining activities due to an event causing a coal mine to be idled, that cessation of coal mining could prohibit us from producing gas from that or related sites until the coal mining activities commence again, which could adversely affect our financial condition or operations. We have 271 Bcf of proved undeveloped reserves that are dependent on the mining of coal by CONSOL Energy.

 

We may lose certain synergistic advantages by separating ourselves from our current owner.

 

Because approximately 17% of our gas production is associated with mining activities by our principal stockholder, coordination between mining and gas operations can optimize overall energy production. We have 271 Bcf of proved undeveloped reserves that are dependent on the mining of coal by CONSOL Energy. If CONSOL Energy were to dispose of a significant interest in us, coordination between us and CONSOL Energy’s mining subsidiaries may be more difficult to accomplish.

 

ITEM 2. PROPERTIES

 

Our corporate headquarters are located at 4000 Brownsville Road, South Park, PA 15129-9545. Our other properties are described under “Gas Operations—Areas of Operation” in ITEM 1.

 

ITEM 3. LEGAL PROCEEDINGS

 

CNX Gas is currently undergoing an audit by Buchanan County, Virginia local taxing authorities for the tax years 1998 through 2001. For these years, CNX Gas has filed appropriate returns and has paid applicable license taxes based on wellhead price calculations. The audit is ongoing with no resolution being proposed by Buchanan County as of December 31, 2005. Additionally, on April 29, 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a “Motion for Judgment Pursuant to the Declaratory Judgment Act Virginia Code §8.01-184” against us in the Circuit Court of the County of Buchanan (At Law No. CL05000149-00) for the year 2002. The complaint alleges that we failed to properly calculate the amount of license taxes we owed to Buchanan County related to our production and sale of CBM gas in Buchanan County. Buchanan County is seeking a determination by the court that we have calculated, and continue to calculate, the license tax in an improper manner. We have continued to pay Buchanan County taxes based on our method of calculating the taxes. However, we have been accruing an additional liability on our balance sheet in an amount based on the difference between our calculation of the tax and Buchanan County’s calculation. We believe that we have calculated the tax correctly and in accordance with the applicable rules and regulations of Buchanan County and intend to vigorously defend our position. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.

 

CDX Gas, LLC has alleged that certain of our vertical to horizontal CBM drilling methods infringe several patents which they own. CDX has demanded that we enter into a business arrangement with CDX to use its patented technology. Alternatively, CDX has informally demanded a royalty of nine to ten percent of the gross production from the wells we drill utilizing the technology allegedly covered by their patents. While CDX has not formally identified the wells where we used the allegedly infringing technology, we believe that 23 of our producing wells to date could be covered by their claim. CDX has also suggested that we breached a confidentiality agreement that one of our affiliates entered into with them in 2001. We deny all of these allegations and intend to vigorously contest them. On November 14, 2005, we filed a complaint for declaratory judgment in the U.S. District Court for the Western District of Pennsylvania, seeking a judicial determination to the effect that the CDX patents are invalid and unenforceable and that we do not infringe any valid and enforceable claim of the CDX patents. CDX has filed an answer and counterclaim denying our allegations of invalidity and alleging that we infringe certain of their patents. This litigation is in a very early stage and we cannot predict the outcome.

 

In 1999, CNX Gas was named in a suit brought by a group of royalty owners that lease gas development rights to CNX Gas in southwest Virginia. The suit alleged the underpayment of royalties to the group of royalty

 

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owners and to a class of plaintiffs who have yet to be determined. The claim of underpayment of royalties related to the interpretation of permissible deductions from production revenues upon which royalties are calculated. The deductions at issue relate to post production expenses of gathering compression and transportation. CNX Gas was ordered to, and subsequently in 2002 paid, approximately $7,000 to the group of royalty owners that brought the suit. An estimate of the payment was appropriately accrued in other cost of goods sold in previous periods. A final payment was made to the plaintiffs in 2003 for approximately $6,000 to adjust all royalties owed to the plaintiffs from the date of the court ruling forward, which effectively settled this case. CNX Gas has also recognized an estimated liability for other similar plaintiffs yet to be determined outside of the aforementioned suit. This amount is included in other liabilities on the balance sheet. To date, approximately $3,900 has been paid to various royalty owners using the court determined deductions from the settled case. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.

 

In addition to the foregoing, CNX Gas is subject to various pending and threatened lawsuits and claims arising in the ordinary course of its business. While the relief claimed in these matters may be significant, we are unable to predict with certainty the ultimate outcome of such lawsuits and claims. We have established reserves for pending litigation which we believe are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against CNX Gas will not materially affect the financial position of CNX Gas.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

 

None.

 

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PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

The shares of CNX Gas Corporation common stock are listed and traded on the New York Stock Exchange (“NYSE”), under the symbol “CXG”. Our common stock began trading on January 19, 2006, following the effectiveness of our resale registration statement on Form S-1.

 

On January 19, 2006, the high and low sales prices of our common stock on the NYSE were $22.65 and $21.78, respectively. On February 15, 2006, the high and low sales prices of our common stock on the NYSE were $22.40 and $21.40, respectively.

 

As of February 10, 2006 there were three holders of record of the Company’s common stock; we believe that there are significantly more beneficial holders of our stock.

 

We currently intend to retain our earnings for the development of our business and do not expect to pay any cash dividends. Other than the special dividend of approximately $420.2 million we paid to CONSOL Energy with the net proceeds from the private placement of the shares of CNX Gas described below, we have not paid any cash dividends from the date of our inception.

 

See Part III, Item 11. Executive Compensation for information relating to CNX Gas’ equity compensation plans.

 

Recent Sales of Unregistered Securities

 

During the past three years, we have issued and sold unregistered securities in the transactions described below:

 

(1) In July, 2005 we issued 100 shares of common stock to Consolidation Coal Company in exchange for $100 in connection with the incorporation of CNX Gas. We relied on the exemption under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), in connection with the offer and sale of those shares.

 

(2) On August 1, 2005, we issued 122,896,567 shares of common stock to our then sole stockholder, Consolidation Coal Company, in exchange for the contribution to us of all of CONSOL Energy Inc.’s (Consolidation Coal Company’s sole stockholder) gas business. We relied on the exemption under Section 4(2) of the Securities Act in connection with the offer and sale of those shares.

 

(3) On August 8, 2005 we completed a private placement of 24,292,754 shares of common stock, 21,778,867 of which were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, 1,086,980 of which were offered and sold to foreign buyers pursuant to Regulation S promulgated under the Securities Act and 1,426,907 of which were offered and sold to accredited investors pursuant Rule 506 under the Securities Act. Friedman, Billings, Ramsey & Co., Inc. (“FBR”) served as the initial purchaser under the Rule 144A and Regulation S offerings and served as our placement agent with respect to the Rule 506 offering. In the Rule 144A and Regulation S offerings, we sold the securities to FBR at a price of $15.04 per share, which was a $0.96 per share discount over the gross offering price to the investors of $16.00 per share. In the Rule 506 offering we sold shares to the investors at $16.00 per share and paid FBR a $0.96 per share commission. Aggregate net proceeds to CNX Gas for the total offering, after deducting discounts and commissions of $23,321,044, was $365,363,020. CNX Gas relied on subscription agreements and associated questionnaires in order to satisfy itself that the requirements of Rule 144A, Regulation S and Rule 506, as applicable, were satisfied. All net proceeds of the above offering were paid to Consolidation Coal Company as a special dividend.

 

(4) On August 11, 2005, following the exercise by FBR of an over-allotment option in connection with the above referenced private placement, we completed the sale of 3,643,913 shares of common stock,

 

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822,702 of which were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, 51,300 of which were offered and sold to foreign buyers pursuant to Regulation S promulgated under the Securities Act and 2,769,911 of which were offered and sold to accredited investors pursuant Rule 506 under the Securities Act. FBR served as the initial purchaser under the Rule 144A and Regulation S offerings and served as our placement agent with respect to the Rule 506 offering. In the Rule 144A and Regulation S offerings, we sold the securities to FBR at a price of $15.04 per share, which was a $0.96 per share discount over the gross offering price to the investors of $16.00 per share. In the Rule 506 offering we sold shares to the investors at $16.00 per share and paid FBR a $0.96 per share commission. Aggregate net proceeds to CNX Gas for the total offering, after deducting discounts and commissions of $3,498,157, was $54,804,452. CNX Gas relied on subscription agreements and associated questionnaires in order to satisfy itself that the requirements of Rule 144A, Regulation S and Rule 506, as applicable, were satisfied. All net proceeds of the above offering were paid to Consolidation Coal Company as a special dividend.

 

(5) In reliance on Rule 701 and Rule 506 of the Securities Act of 1933, during August 2005, CNX Gas issued options to purchase CNX Gas common stock to our employees and executive officers at an exercise price of $16.00 per share and restricted stock units to our non-employee and non-CONSOL Energy employee directors. We also granted a small number of options to new employees in September 2005 at an exercise price of $20.50 per share, and in November 2005, at an exercise price of $20.75 per share. A total of 358,370 options to purchase CNX Gas common stock were granted to CNX Gas employees, other than our executive officers. Messrs. DeIuliis, Smith, Johnson and Bench received stock options in the aggregate amount of 670,556 shares and Mr. Johnson received 2,969 restricted stock units. Similarly, we granted restricted stock units to each director of CNX Gas that is not an employee of CNX Gas or CONSOL Energy. Mr. Baxter, chairman of the board of directors, was granted 60,000 restricted stock units. Each other such director received 10,000 restricted stock units. The foregoing one-time grants were made in consideration for future service of the employees, executive officers and directors to CNX Gas.

 

The registration statement on Form S-1 (SEC File No. 333-127483), as amended, filed by the Company was declared effective by the Securities and Exchange Commission on January 18, 2006. CNX Gas registered for sale 27,936,667 shares of common stock, all of which were held by selling stockholders named in the registration statement. Under the registration statement, the shares can be offered and sold by the selling stockholders in one or more transactions at fixed prices, prevailing market prices or negotiated prices. CNX Gas did not sell any shares for our own account and did not receive any proceeds from the sale of securities by any selling stockholders. CNX Gas incurred expenses as detailed in the registration statement of approximately $1.17 million.

 

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ITEM 6. SELECTED FINANCIAL DATA

 

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the twelve months ended December 31, 2005, December 31, 2004 and December 31, 2003, are derived from our audited consolidated financial statements, including the consolidated balance sheets at December 31, 2005 and 2004 and the related consolidated statements of income and cash flows for each of the twelve months ended December 31, 2005, 2004, and 2003, and the notes thereto appearing herein. The selected consolidated financial data for, and as of the end of, the twelve months ended December 31, 2002 and the twelve months ended December 31, 2001 are derived from our unaudited consolidated financial statements, and in the opinion of management include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the financial statements and related notes included in this Annual Report.

 

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

 

STATEMENTS OF INCOME DATA

(In thousands)


  Twelve Months Ended December 31,

 
  2005

  2004

  2003

  2002

  2001

 

RESULTS OF OPERATIONS

                               

Sales—Outside

  $ 322,382   $ 256,579   $ 178,326   $ 139,343   $ 119,047  

Sales—Related Party

    6,052     22,036     32,572     9,542     5,288  

Sales—Purchased Gas

    275,148     112,005     —       —       —    

Other income

    9,859     6,916     4,485     2,068     403  
   

 

 

 

 


TOTAL REVENUE AND OTHER INCOME

    613,441     397,536     215,383     150,953     124,738  
   

 

 

 

 


Lifting costs

    26,794     23,939     20,761     16,297     13,513  

Gathering and compression costs

    40,623     37,021     28,914     24,749     18,759  

Royalty

    36,641     32,914     24,200     12,214     10,659  

Purchased gas costs

    278,720     113,063     —       —       —    

Other

    21,147     16,274     21,771     16,169     17,863  

Equity in (earnings) loss of affiliates

    149     2,423     2,932     3,312     (16,788 )

Selling, general and administrative

    7,596     6,327     3,194     1,140     2,446  

Depreciation, depletion and amortization

    35,039     32,889     33,600     34,368     21,175  

Interest Expense

    14     —       —       —       —    
   

 

 

 

 


TOTAL COSTS AND EXPENSES

    446,723     264,850     135,372     108,249     67,627  
   

 

 

 

 


Earnings before income taxes and cumulative effect of change in accounting principle

    166,718     132,686     80,011     42,704     57,111  

Income taxes

    64,550     51,898     31,202     16,677     22,330  
   

 

 

 

 


Earnings before cumulative effect of change in accounting principle

    102,168     80,788     48,809     26,027     34,781  

Cumulative effect of change in accounting for gas well closing costs (net of tax impact of $1,879)

    —       —       2,905     —       —    
   

 

 

 

 


NET INCOME

  $ 102,168   $ 80,788   $ 51,714   $ 26,027   $ 34,781  
   

 

 

 

 


Earnings per share from continuing operations

                               

Basic

  $ 0.76   $ 0.66   $ 0.40   $ 0.21   $ 0.28  
   

 

 

 

 


Dilutive

  $ 0.76   $ 0.66   $ 0.40   $ 0.21   $ 0.28  
   

 

 

 

 


Earnings per share from net income

                               

Basic

  $ 0.76   $ 0.66   $ 0.42   $ 0.21   $ 0.28  
   

 

 

 

 


Dilutive

  $ 0.76   $ 0.66   $ 0.42   $ 0.21   $ 0.28  
   

 

 

 

 


Weighted average number of common shares outstanding

                               

Basic

    134,071,334     122,896,667     122,896,667     122,896,667     122,896,667  
   

 

 

 

 


Dilutive

    134,137,219     122,988,359     122,988,359     122,988,359     122,988,359  
   

 

 

 

 


 

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BALANCE SHEETS DATA

(In thousands)


   At December 31,

 
   2005

    2004

    2003

    2002

    2001

 

Working capital (deficiency)

   $ 3,720     $ (35,030 )   $ (7,971 )   $ 2,868     $ 6,984  

Total assets

     874,856       723,290       664,635       598,236       527,109  

Short-term debt

     —         —         —         —         —    

Long-term debt (including current portion)

     —         —         —         —         —    

Total deferred credits and other liabilities

     109,226       205,614       170,520       114,902       86,701  

Stockholders’ equity

     679,472       462,556       464,232       468,617       431,582  

CASH FLOW STATEMENTS DATA (5)

(In thousands)


  

Twelve Months

Ended December 31,


 
   2005

    2004

    2003

    2002

    2001

 

Net cash provided by operating activities

   $ 144,997     $ 175,350     $ 143,133     $ 88,643     $ 63,781  

Net cash (used in) investing activities

     (108,287 )     (93,114 )     (90,605 )     (101,472 )     (203,168 )

Net cash (used in) provided by financing activities

     (16,640 )     (82,237 )     (52,526 )     12,831       139,387  

OTHER OPERATING DATA


  

Twelve Months

Ended December 31,


 
   2005

    2004

    2003

    2002

    2001

 

Net sales volumes (Bcf) (1)

     48.39       48.56       44.46       41.30       33.92  

Average sales price including effects of financial settlements ($ per mcf) (1)(2)

   $ 6.08     $ 5.09     $ 4.14     $ 3.17     $ 4.07  

Total average costs ($ per mcf) (1)

   $ 2. 72     $ 2.45     $ 2.43     $ 2.25     $ 2.17  

Net estimated proved reserves (Bcfe) (1)(3)

     1,130       1,045       1,004       961       1,023  

OTHER FINANCIAL DATA

(In thousands)


  

Twelve Months

Ended December 31,


 
   2005

    2004

    2003

    2002

    2001

 

Capital expenditures

   $ 110,752     $ 89,753     $ 83,869     $ 61,705     $ 211,715  

EBIT (4)

     166,314       132,686       80,011       42,704       57,111  

EBITDA (4)

     201,353       165,575       113,611       77,072       78,286  

(1) For entities that are not wholly owned but in which CNX Gas owns at least a 50% equity interest, includes a percentage of their net production, sales or reserves equal to CNX Gas’ percentage equity ownership. Knox Energy makes up the equity earnings data in 2005, 2004, 2003 and part of 2002. Greene Energy was part of the equity earnings in 2002 and 2001. Pocahontas Gas Partnership accounts for the majority of the information reported as an equity affiliate for approximately eight months in the December 31, 2001 period. Sales of gas produced by equity affiliates were 0.23 Bcf for the twelve months ended December 31, 2005, 0.20 Bcf for the twelve months ended December 31, 2004, 0.08 Bcf for the twelve months ended December 31, 2003, 0.22 Bcf for the twelve months ended December 31, 2002 and 5.5 Bcf for the twelve months ended December 31, 2001.
(2) Represents average net sales price after the effect of derivative transactions.
(3) Represents proved developed and proved undeveloped gas reserves at period end.
(4)

EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBIT and EBITDA are not measures of performance calculated in accordance with accounting principles generally accepted in the United States of America, management believes that they are useful to an investor in evaluating CNX Gas because they are used as measures to evaluate a company’s operating performance before debt expense and cash flow. EBIT and EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as substitute for measures of performance in accordance with accounting principles generally accepted in the United States of America. In addition, because EBIT and EBITDA are not calculated identically by all companies, the presentation here may not be comparable to

 

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other similarly titled measures of other companies. Management’s discretionary use of funds depicted by EBIT and EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconciliation of EBIT and EBITDA to financial net income is as follows:

 

    

Twelve Months

Ended December 31,


(In thousands)


   2005

   2004

   2003

    2002

   2001

Net income

   $ 102,168    $ 80,788    $ 51,714     $ 26,027    $ 34,781

Add: Interest expense

     14      —        —         —        —  

Less: Interest income

     418      —        —         —        —  

Less: Cumulative effect of changes in accounting for gas well plugging costs, net of income taxes of $1,879

     —        —        (2,905 )     —        —  

Add: Income tax expense

     64,550      51,898      31,202       16,677      22,330
    

  

  


 

  

Earnings before net interest and taxes (EBIT)

     166,314      132,686      80,011       42,704      57,111

Add: Depreciation, depletion and amortization

     35,039      32,889      33,600       34,368      21,175
    

  

  


 

  

Earnings before net interest, taxes and depreciation, depletion and amortization (EBITDA)

   $ 201,353    $ 165,575    $ 113,611     $ 77,072    $ 78,286
    

  

  


 

  

 

(5) Amounts shown for the twelve months ended December 31, 2005 reflect the reclassification of certain amounts from the comparable line items on the unaudited consolidated statements of cash flows included in our press release dated January 25, 2006.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion and analysis should be read in conjunction with “Selected Consolidated Financial and Other Data” and our consolidated financial statements and related notes appearing elsewhere in this Annual Report. This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. See “PART I—Forward Looking Statements” and PART I-Item 1.A “Risk Factors”.

 

Overview

 

We are a natural gas exploration, development and production company with operations in the Appalachian Basin. We have operations in several states in the Appalachian Basin. We primarily are a CBM gas producer with industry-leading expertise in this type of gas extraction.

 

Effective as of August 8, 2005, we separated our gas business from CONSOL Energy. We undertook this separation to achieve the following objectives:

 

    achieve a higher valuation for our business than we believe could be achieved if we remained part of CONSOL Energy;

 

    allow us to use our own capital and borrowing capability, rather than compete for capital with the mining business, to more rapidly expand gas production from our proven reserves and unproven acreage; and

 

    allow our key managers to focus solely on the growth and operation of CNX Gas.

 

The success of our operations substantially depends upon rights we received from CONSOL Energy. As a part of our separation from CONSOL Energy, CONSOL Energy transferred to CNX Gas various subsidiaries and joint venture interests as well as all of CONSOL Energy’s ownership or rights to CBM and natural gas and certain related surface rights. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with their coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements with CONSOL Energy under which they will, among other things, provide us certain corporate staff services and coordinate our tax filings.

 

In August 2005, CNX Gas sold 27.9 million shares in a private placement transaction. The aggregate net proceeds of the transaction (approximately $420.2 million) were used to pay a special dividend to CONSOL Energy. CONSOL Energy continues to beneficially own 81.5% of our outstanding common stock.

 

We do not currently have any plans to pay dividends; rather, we intend to invest available cash into the development of our business, provided that we can do so at rates of return that exceed our cost of capital.

 

Our goal is to create shareholder value by efficiently increasing production and adding reserves, with a continued emphasis on safety. We believe that by working safely, we can enhance our productivity and continue to be a cost leader in the industry. During 2005, we achieved the following:

 

    generated net income in excess of $100 million;

 

    increased our proved reserve base by replacing 271 percent of our 2005 production;

 

    worked another year without a lost time accident; and

 

    nearly matched our 2004 production, despite losing over 4 Bcf of production due to affiliated mine situations and unaffiliated maintenance related capacity constraints on CNX Gas transportation capacity on the Columbia interstate pipeline.

 

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Our financial statements are consolidated within CONSOL Energy’s financial statements. For periods prior to August 8, 2005, when we were a wholly-owned subsidiary of CONSOL Energy, we developed separate financial statements for CNX Gas that allow us to report results as an independent company even though our results also are consolidated into CONSOL Energy’s financial statements.

 

Results of Operations

 

Twelve Months Ended December 31, 2005 compared with Twelve Months Ended December 31, 2004

(Amounts reported in thousands)

 

Net Income

 

Net income changed primarily due to the following items:

 

     2005

   2004

  

Dollar

Variance


   

Percentage

Change


 

Revenue and Other Income:

                            

Outside Sales

   $ 322,382    $ 256,579    $ 65,803     25.6 %

Related Party Sales

     6,052      22,036      (15,984 )   (72.5 )%

Purchased Gas Sales

     275,148      112,005      163,143     145.7 %

Other Income

     9,859      6,916      2,943     42.6 %
    

  

  


     

Total Revenue and Other Income

     613,441      397,536      215,905     54.3 %
    

  

  


     

Costs and Expenses:

                            

Lifting Costs

     26,794      23,939      2,855     11.9 %

Gathering and Compression Costs

     40,623      37,021      3,602     9.7 %

Royalty

     36,641      32,914      3,727     11.3 %

Purchased Gas Costs

     278,720      113,063      165,657     146.5 %

Other

     21,147      16,274      4,873     29.9 %

Equity in (Earnings) Loss of Affiliates

     149      2,423      (2,274 )   (93.9 )%

Selling, General and Administrative

     7,596      6,327      1,269     20.1 %

Depreciation, Depletion and Amortization

     35,039      32,889      2,150     6.5 %

Interest Expense

     14      —        14     100.0 %
    

  

  


     

Total Costs and Expenses

     446,723      264,850      181,873     68.7 %
    

  

  


     

Earnings Before Income Taxes

     166,718      132,686      34,032     25.6 %

Income Taxes

     64,550      51,898      12,652     24.4 %
    

  

  


     

Net Income

   $ 102,168    $ 80,788    $ 21,380     26.5 %
    

  

  


     

 

Net income for 2005 was improved primarily due to increased average sales prices. The increased revenues were offset, in part, by higher costs attributable to production taxes, royalties, firm transportation charges and general administrative charges.

 

Revenue and Other Income

 

Revenue and other income increased due to the following items:

 

     2005

   2004

  

Dollar

Variance


   

Percentage

Change


 

Revenue and Other Income:

                            

Outside Sales

   $ 322,382    $ 256,579    $ 65,803     25.6 %

Related Party Sales

     6,052      22,036      (15,984 )   (72.5 )%

Purchased Gas Sales

     275,148      112,005      163,143     145.7 %

Other Income

     9,859      6,916      2,943     42.6 %
    

  

  


     

Total Revenue and Other Income

   $ 613,441    $ 397,536    $ 215,905     54.3 %
    

  

  


     

 

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Table of Contents

The increase in gas sales revenue was primarily due to a higher average sales price per thousand cubic feet in 2005 compared to 2004. Related party sales decreased due to the impacts of the Buchanan mine incidents. Purchased gas sales revenue increased due to the additional matching buy/sell arrangements required to sell our gas.

 

     2005

   2004

   Variance

   

Percentage

Change


 

Produced Gross Sales Volumes (Bcf)

     54.7      55.3      (0.6 )   (1.1 )%

Average Gross Sales Price (per mcf)

   $ 6.00    $ 5.04    $ 0.96     19.0 %

 

We believe the 2005 gas market price increases were largely driven by continued concerns over levels of North American gas production, as well as increased oil prices and favorable economic conditions in the United States that encourage demand for natural gas. The adverse effect of the 2005 hurricane season also shut-in significant portions of Gulf Coast gas, increasing the tight supply of gas, and leading to even higher prices in 2005. CNX Gas enters into various physical gas supply transactions with both gas marketers and other counterparties for terms varying in length. CNX Gas has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These physical and financial hedges represented approximately 70% of our produced gas sales volumes for the twelve months ended December 31, 2005 at an average price of $4.77 per mcf. Despite the loss of approximately 4.0 Bcf related to the CONSOL Energy Buchanan Mine incidents and 1.4 Bcf related to maintenance related capacity constraints on CNX Gas transportation capacity on the Columbia interstate pipeline, sales volumes are only slightly lower in the 2005 period compared to the 2004 period. CNX Gas was able to offset these production losses with additional volumes coming online from our on-going drilling program, and by successfully initiating a frac well enhancement and stimulation program on wells unaffected by the mine incidents throughout the current year.

 

As a result of increased demand for pipeline use on the Columbia interstate pipeline and the potential for curtailment on portions of the shipment capacity allocated to CNX Gas, we purchased firm transportation capacity on the pipeline during 2005. This arrangement offset a portion of the expected impact from periodic curtailments. In April 2005, CNX Gas was given notice by Columbia regarding reductions in allowable gas flows due to routine maintenance and construction activities. Interruptible gas was completely shut in and our contracted firm transportation flows were reduced by 60%, which resulted in reduced revenues of approximately $6.8 million along with other smaller curtailments throughout the year that were also eventually lifted. Although CNX Gas anticipates that these pipeline constraints will be an on-going issue for the foreseeable future, we also intend to gain access to the ETNG pipeline, which is south of our Central Appalachia operations. ETNG has received the approval of the Federal Energy Regulatory Commission (“FERC”) for the construction of a 32-mile lateral pipeline, called Jewell Ridge Lateral, that will transport gas from our Central Appalachia operations to ETNG’s major transportation pipeline to the south. The FERC approval is subject to certain conditions, which ETNG is working to satisfy. Jewell Ridge Lateral is expected to be in service in the summer of 2006 and will provide us with an alternate transportation route to the northeast markets we currently serve as well as access to east coast markets.

 

Additionally, we simultaneously purchased gas from and sold gas to other counterparties between the segmentation and interruptible pools on the Columbia pipeline in order to satisfy obligations to certain customers. In accordance with EITF 99-19, we have increased our revenues and our costs. Sales of purchased gas volumes have increased primarily due to CNX Gas utilizing higher levels of firm transportation throughout the 2005 period that required us to purchase from and sell to other counterparties. CNX Gas began to enter into this type of transaction in May of 2004.

 

     2005

   2004

   Variance

  

Percentage

Change


 

Purchased Gas Sales Volumes (Bcf)

     28.7      17.5      11.2    64.0 %

Average Sales Price (per mcf)

   $ 9.59    $ 6.39    $ 3.20    50.1 %

 

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Other income consists of royalty income, third party gathering revenue and other miscellaneous income:

 

     2005

   2004

  

Dollar

Variance


  

Percentage

Change


 

Royalty Income

   $ 8,158    $ 5,726    $ 2,432    42.5 %

Third Party Gathering Revenue

     1,110      1,109      1    0.1 %

Interest Income

     418      —        418    100.0 %

Other Miscellaneous

     173      81      92    113.6 %
    

  

  

      

Total Other Income

   $ 9,859    $ 6,916    $ 2,943    42.6 %
    

  

  

      

 

Royalty income increased in 2005 compared to 2004 due to increased gas prices and additional production on existing contracts. Royalty income received from third parties is calculated as a percentage of the third parties sales price.

 

Third party gathering revenue is flat due to the net effect of higher volumes transported through gathering systems, offset by reduced rates in 2005 compared to 2004.

 

Interest income increased $418 in 2005 as a result of CNX Gas retaining cash collections as a separate stand alone company. In 2004 CNX Gas was part of CONSOL Energy’s securitization program and retained no cash resulting in zero interest income.

 

Other Miscellaneous consisted of additional income from miscellaneous transactions that occurred throughout both periods, none of which were individually material.

 

Costs and Expenses

 

Increased costs and expenses in 2005 were impacted by purchased gas, increased firm transport, higher prices resulting in higher royalties and higher administrative expense and are made up of the following components:

 

     2005

   2004

  

Dollar

Variance


   

Percentage

Change


 

Costs and Expenses:

                            

Lifting Costs

   $ 26,794    $ 23,939    $ 2,855     11.9 %

Gathering and Compression Costs

     40,623      37,021      3,602     9.7 %

Royalty

     36,641      32,914      3,727     11.3 %

Purchased Gas Costs

     278,720      113,063      165,657     146.5 %

Other

     21,147      16,274      4,873     29.9 %

Equity in (Earnings) Loss of Affiliates

     149      2,423      (2,274 )   (93.9 )%

Selling, General & Administrative

     7,596      6,327      1,269     20.1 %

Depreciation, Depletion & Amortization

     35,039      32,889      2,150     6.5 %

Interest Expense

     14      —        14     100.0 %
    

  

  


     

Total Costs and Expenses

   $ 446,723    $ 264,850    $ 181,873     68.7 %
    

  

  


     

 

     2005

   2004

   Variance

   

Percentage

Change


 

Produced Gross Sales Volumes (Bcf)

     54.7      55.3      (0.6 )   (1.1 )%

Average Lifting Costs (per mcf)

   $ 0.49    $ 0.43    $ 0.06     14.0 %

 

Lifting costs per unit sold increased $0.06 per mcf in the period, of which $0.03 per mcf was due to higher production taxes in 2005 compared to 2004 driven by higher realized sales price. Well maintenance fees

 

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increased $0.02 per mcf due to additional wells being serviced in the current year. Various other transactions, none of which were individually material, also contributed to the increase in per unit costs.

 

     2005

   2004

   Variance

   

Percentage

Change


 

Produced Gross Sales Volumes (Bcf)

     54.7      55.3      (0.6 )   (1.1 )%

Average Gathering and Compression Costs (per mcf)

   $ 0.74    $ 0.67    $ 0.07     10.4 %

 

The increase in gathering and compression costs per unit was attributable to an additional $0.03 per mcf charge for the purchase of firm transportation capacity on the Columbia interstate pipeline because of potential curtailments on portions of shipment capacity allocated to CNX Gas as a result of increased demand for pipeline access in the 2005 period. CNX Gas began to purchase firm transportation capacity on the pipeline in May 2004. Gathering and compression costs per unit also increased approximately $0.02 per mcf due to additional power expense, as a result of converting several compressors from gas powered to electric powered in the current year. Gathering and compression unit costs also increased due to various other transactions, none of which were individually material.

 

CNX Gas royalty expense increased as a result of the 19.0% increase in the average gas sales price received.

 

In connection with the purchase of firm transportation capacity on the Columbia pipeline, we purchased from and sold to other gas suppliers, which increased our revenues and our costs. CNX Gas believes this type of transaction may continue as a result of increased capacity demands on the Columbia pipeline. The 2004 period included a smaller volume of firm transportation activity as CNX Gas did not begin to purchase this capacity until May of 2004. Purchased gas cost information is as follows:

 

     2005

   2004

   Variance

  

Percentage

Change


 

Purchased Gas Cost Volumes (Bcf)

     28.7      17.5      11.2    64.0 %

Average Purchased Gas Costs (per mcf)

   $ 9.71    $ 6.45    $ 3.26    50.5 %

 

Other costs and expenses increased due to the following items:

 

     2005

   2004

    Dollar
Variance


   

Percentage

Change


 

Imbalance

   $ 899    $ (266 )   $ 1,165     438.0 %

Direct Administration

     8,053      7,280       773     10.6 %

Well Site General Maintenance

     3,229      3,135       94     3.0 %

Gob Collection Costs

     3,280      3,401       (121 )   (3.6 )%

Accounts Receivable Securitization Fees

     1,328      1,964       (636 )   (32.4 )%

Miscellaneous

     4,358      760       3,598     473.4 %
    

  


 


     

Total Other Costs and Expenses

   $ 21,147    $ 16,274     $ 4,873     29.9 %
    

  


 


     

 

The gas imbalance has shifted from an over-delivered position in 2004 to an under-delivered position in 2005, and therefore resulted in expense for 2005 compared to income in 2004. Because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers, CNX Gas is responsible for monitoring this imbalance and requesting adjustments to contracted volumes as circumstances warrant. This increase in imbalance cost was offset by corresponding increases in gas sales revenue.

 

Direct administration costs increased in the 2005 period due to additional staffing needs as part of the separation of CNX Gas from CONSOL Energy.

 

Well site general maintenance costs increased in 2005 due to the additional wells being drilled as part of the on-going drilling program.

 

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Table of Contents

Gob collection costs decreased slightly in 2005 due to the reduced number of gob wells drilled as a result of the mine incidents that occurred in the current year.

 

Accounts receivable securitization fees have decreased as a result of CNX Gas no longer being a part of this program as of the date of separation. Prior to separation, CNX Gas sold eligible receivables to a CONSOL Energy subsidiary on a discounted basis. The fees above represent the discounted portion on the sale of those receivables.

 

Miscellaneous costs and expenses increased primarily due to additional administrative expenses as a result of CNX Gas becoming a stand alone company in 2005 that were not incurred in the prior period, as well as various other miscellaneous transactions that occurred in both periods, none of which were individually material.

 

Equity in (earnings) loss of affiliates improved in 2005 compared to 2004 as follows:

 

     2005

    2004

   

Dollar

Variance


   

Percentage

Change


 

Buchanan Generation

   $ 287     $ 915     $ (628 )   (68.6 )%

Knox Energy

     (92 )     1,535       (1,627 )   (106.0 )%

Coalfield Pipeline

     (46 )     (27 )     (19 )   70.4 %
    


 


 


     

Total Equity in (Earnings) Loss of Affiliates

   $ 149     $ 2,423     $ (2,274 )   (93.9 )%
    


 


 


     

 

Buchanan Generation’s losses were lower in 2005 compared to 2004 primarily due to the facility being run for more megawatt hours in 2005 compared to 2004. This improvement was offset, in part, by increased fuel charges due to higher average gas sales prices in 2005 compared to 2004.

 

Knox Energy had earnings in 2005 compared to a loss in 2004 primarily due to production increases at the joint venture and additional service revenue. CNX Gas owns a 50% interest in this joint venture. CNX Gas’ production percentage increased due to a settlement agreement between CNX Gas and our partner in the joint venture in which CNX Gas now fully owns more wells. Prior to the settlement agreement, CNX Gas shared ownership interest in these wells proportionately with our partner.

 

Equity in earnings of Coalfield Pipeline improved in 2005 compared to 2004 due primarily to increased volumes transported through its gathering system.

 

Selling, general and administrative increased to $7,596 in 2005 from $6,327 in 2004 primarily due to higher charges for legal fees, accounting fees, payroll processing and other service costs. Additional costs have been incurred as a result of the separation of CNX Gas from CONSOL Energy.

 

Depreciation, depletion and amortization have increased due to the following items:

 

     2005

   2004

  

Dollar

Variance


  

Percentage

Change


 

Production

   $ 23,531    $ 22,353    $ 1,178    5.3 %

Gathering

     11,508      10,536      972    9.2 %
    

  

  

      

Total Depreciation, Depletion and Amortization

   $ 35,039    $ 32,889    $ 2,150    6.5 %
    

  

  

      

 

The increase in production related depreciation, depletion and amortization was primarily due to a slightly higher unit-of-production rate in 2005 compared to 2004. Rates are generally calculated using the net book value of assets at the end of the year divided by proven developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased due to additional assets coming on line in 2005.

 

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Interest expense relates to charges for activity on the $200 million credit facility established in October of 2005.

 

Income Taxes

 

     2005

    2004

    Variance

   

Percentage

Change


 

Earnings Before Income Taxes

   $ 166,718     $ 132,686     $ 34,032     25.6 %

Tax Expense

   $ 64,550     $ 51,898     $ 12,652     24.4 %

Effective Income Tax Rate

     38.7 %     39.1 %     (0.4 )%      

 

CNX Gas’ effective tax rate decreased in 2005 primarily due to a special deduction provided by the American Jobs Creation Act of 2004.

 

Twelve Months Ended December 31, 2004 compared with Twelve Months Ended December 31, 2003 (Amounts reported in thousands)

 

Net Income

 

Net income changed primarily due to the following items:

 

     2004

   2003

  

Dollar

Variance


   

Percentage

Change


 

Revenue and other Income:

                            

Outside Sales

   $ 256,579    $ 178,326    $ 78,253     43.9 %

Related Party Sales

     22,036      32,572      (10,536 )   (32.3 )

Purchased Gas Sales

     112,005      —        112,005     100.0  

Other Income

     6,916      4,485      2,431     54.2  
    

  

  


     

Total Revenue and Other Income

     397,536      215,383      182,153     84.6  
    

  

  


     

Costs and Expenses:

                            

Lifting Costs

     23,939      20,761      3,178     15.3  

Gathering and Compression Costs

     37,021      28,914      8,107     28.0  

Royalty

     32,914      24,200      8,714     36.0  

Purchased Gas Costs

     113,063      —        113,063     100.0  

Other

     16,274      21,771      (5,497 )   (25.2 )

Equity in (Earnings) Loss of Affiliates

     2,423      2,932      (509 )   (17.4 )

Selling, General & Administrative

     6,327      3,194      3,133     98.1  

Depreciation, Depletion & Amortization

     32,889      33,600      (711 )   (2.1 )
    

  

  


     

Total Cost and Expenses

     264,850      135,372      129,478     95.6  
    

  

  


     

Earnings Before Income Taxes & Cumulative Effect of Change in Accounting Principle

     132,686      80,011      52,675     65.8  

Income Taxes

     51,898      31,202      20,696     66.3  

Earnings Before Cumulative Effect of Change in Accounting

     80,788      48,809      31,979     65.5  

Cumulative Effect of Change in Accounting

     —        2,905      (2,905 )   (100.0 )
    

  

  


     

Net Income

   $ 80,788    $ 51,714    $ 29,074     56.2 %
    

  

  


     

 

Net income for 2004 was improved primarily due to increased production and increased average sales prices for gas. The increased revenues were offset, in part, by higher cost of goods sold attributable to higher sales volumes of gas and to higher unit costs for gas produced. Higher cost of gas produced was primarily attributable to increased royalty cost and cost of firm transportation incurred by the gas operations.

 

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Table of Contents

Revenue and Other Income

 

Revenue and other income increased due to the following items:

 

     2004

   2003

  

Dollar

Variance


   

Percentage

Change


 

Revenue and Other Income:

                            

Outside Sales

   $ 256,579    $ 178,326    $ 78,253     43.9 %

Related Party Sales

     22,036      32,572      (10,536 )   (32.3 )

Purchased Gas Sales

     112,005      —        112,005     100.0  

Other Income

     6,916      4,485      2,431     54.2  
    

  

  


     

Total Revenue and Other Income

   $ 397,536    $ 215,383    $ 182,153     84.6 %
    

  

  


     

 

The increase in gas sales revenue, both outside and related party combined, was primarily due to a higher average sales price per mcf and increased volumes sold in 2004 compared to 2003.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Produced Gross Sales Volumes (Bcf)

     55.3      50.7      4.6    9.1 %

Average Sales Price (per mcf)

   $ 5.04    $ 4.16    $ 0.88    21.2 %

 

We believe that the 2004 gas market price increases were largely driven by continued concerns about declining North American gas production, as well as increased oil prices and the economic recovery which resulted in greater electricity use in our principal markets. CNX Gas enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CNX Gas has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. In 2004, these cash flow hedges represented 28% of our produced sales volumes at an average price of $5.10 per mcf. At year end, we intend these transactions to cover approximately 17% of our estimated 2005 production volume. CNX Gas sold 84% of its gas sales volumes for the twelve months ended December 31, 2004 under fixed priced contracts at an average price of $4.96 per mcf compared to 90% of its gas sales volumes under fixed price contracts for the twelve months ended December 31, 2003 at an average of $3.99 per mcf. Higher sales volumes in 2004 were a result of wells coming on line from the ongoing drilling program, which allowed CNX Gas to take advantage of increased prices.

 

Due to the anticipated curtailment in the shipment capacity allocated to CNX Gas as a result of increased demand for pipeline use on the Columbia interstate pipeline, CNX Gas purchased firm transportation capacity on the pipeline. The first firm transportation agreement covered the May 2004 through October 2004 period. In November 2004, CNX Gas entered into an extended firm transportation agreement for use on the pipeline. This agreement covered the November 2004 through October 2006 period and assured pipeline capacity of approximately 20% of our projected production for the same period. In addition, in connection with the purchase of firm transportation capacity on Columbia’s pipeline, we purchased gas from and sold gas to other gas suppliers, which increased our revenues and our costs.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Purchased Gas Sales Volumes (Bcf)

     17.5    —        17.5    100.0 %

Average Sales Price (per mcf)

   $ 6.39    —      $ 6.39    100.0 %

 

Other income consists of royalty income, third party gathering revenue and other miscellaneous income.

 

     2004

   2003

  

Dollar

Variance


  

Percentage

Change


 

Royalty Income

   $ 5,726    $ 3,967    $ 1,759    44.3  

Third Party Gathering Revenue

     1,109      440      669    152.0  

Other Miscellaneous

     81      78      3    3.8  
    

  

  

      

Total Other Income

   $ 6,916    $ 4,485    $ 2,431    54.2 %
    

  

  

      

 

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Royalty income increased in 2004 compared to 2003 due to increased gas prices and additional contracts being initiated. Royalty income received from third parties is calculated as a percentage of the third parties’ sales price.

 

Third party gathering revenue has increased due to higher volumes transported through gathering systems for third parties in 2004 compared to 2003. The increased volumes are attributable to volumes of gas moved on behalf of two additional parties through CNX Gas’ gathering systems to Columbia’s interstate gas pipeline.

 

Other income increased for 2004 due to miscellaneous transactions that occurred throughout both periods, none of which were individually material.

 

Costs and Expenses

 

Increased cost of goods sold and other charges in 2004 and 2003 were made up of the following components:

 

     2004

   2003

   Dollar
Variance


    Percentage
Change


 

Cost of Goods Sold and Other Charges:

                            

Lifting Costs

   $ 23,939    $ 20,761    $ 3,178     15.3 %

Gathering and Compression Costs

     37,021      28,914      8,107     28.0  

Royalty

     32,914      24,200      8,714     36.0  

Purchased Gas Costs

     113,063      —        113,063     100.0  

Other

     16,274      21,771      (5,497 )   (25.2 )

Equity in (Earnings) Loss of Affiliates

     2,423      2,932      (509 )   (17.4 )

Selling, General & Administrative

     6,327      3,194      3,133     98.1  

Depreciation, Depletion & Amortization

     32,889      33,600      (711 )   (2.1 )
    

  

  


 

Total Cost and Expenses

   $ 264,850    $ 135,372    $ 129,478     95.6 %
    

  

  


 

 

Increased gas production costs were due to increased sales volumes and increased unit costs.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Produced Gross Sales Volumes (Bcf)

     55.3      50.7      4.6    9.1 %

Average Lifting Costs (per mcf)

   $ 0.43    $ 0.41    $ 0.02    4.9 %

 

Gas production costs per unit sold were higher in 2004 compared to 2003 due to increased severance tax charges. Severance taxes are calculated as 3% of gas sales price. Due to the 21.2% average sales price increase, severance taxes have increased approximately $0.03 per mcf. The increased severance taxes were offset, in part, by reduced well-head maintenance costs. Maintenance costs were lower in 2004 compared to 2003 due mainly to the timing of the completion of work.

 

Gathering and compression costs increased due primarily to increased unit costs and increased sales volumes.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Production Gross Sales Volumes (Bcf)

     55.3      50.7      4.6    9.1 %

Average Gathering and Compression Costs (per mcf)

   $ 0.67    $ 0.57    $ 0.10    17.5 %

 

The increase in gathering and compression costs per unit were primarily due to approximately $0.08 per mcf increase related to the purchase of firm transportation capacity on the Columbia pipeline because of potential curtailments on portions of the shipment capacity allocated to CNX Gas as a result of increased demand for

 

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pipeline transportation capacity. CNX Gas purchased firm transportation capacity on the pipeline from the May 2004 through October 2004 period to assure firm pipeline capacity of our projected production. In November 2004, CNX Gas entered into an extended firm transportation agreement with Columbia’s pipeline. This arrangement covers November 2004 through October 2006. The purchased firm transportation capacity on the pipeline represents approximately 20% of our projected production for the same period. Increased unit costs were also due to third party consulting fees related to the treatment equipment that removes carbon dioxide from the gas stream. The treatment equipment was put into production in February 2004 and took several months to become fully integrated into CNX Gas’ gathering system.

 

Royalty costs increased primarily due to the 21.2% increase in average sales price per mcf in 2004 compared to 2003.

 

In connection with the purchase of firm transportation capacity on Columbia’s pipeline, we purchased from and sold to other gas suppliers, which increased our revenues and our costs. CNX Gas believes this type of transaction may continue as a result of increased capacity demands on the Columbia pipeline. Purchased gas cost information is as follows:

 

     2004

   2003

   Variance

  

Percentage

Change


 

Purchased Gas Sales Volumes (Bcf)

     17.5    —        17.5    100.0 %

Average Cost Per Thousand cubic feet (per mcf)

   $ 6.45    —      $ 6.45    100.0 %

 

Other costs and expenses decreased due to the following items:

 

     2004

   2003

   Dollar
Variance


    Percentage
Change


 

Well Site General Maintenance

   $ 3,135    $ 2,049    $ 1,086     53.0 %

Accounts Receivable Securitization Fees

     1,964      1,103      861     78.1  

Land Rental Fees

     534      1,003      (469 )   (46.8 )

Well Plugging Accretion Expense

     525      450      75     16.7  

Legal Settlements

     —        5,728      (5,728 )   (100.0 )

Miscellaneous

     10,116      11,438      (1,322 )   (11.6 )
    

  

  


     

Total Other Cost

   $ 16,274    $ 21,771    $ (5,497 )   (25.2 )%
    

  

  


     

 

Well site general maintenance costs increased in 2004 due to the additional wells being drilled as part of our on-going drilling program.

 

Accounts receivable securitization fees have increased due to higher accounts receivable balances being sold to a subsidiary of CONSOL Energy, our principal stockholder, in 2004 compared to 2003. Higher accounts receivable balances available for sale were attributable to higher average sales prices and volumes in the period to period comparison. CNX Gas sells eligible receivables to CONSOL Energy’s subsidiary on a discounted basis. The fees above represent the discount portion on the sale of the receivables. CNX Gas discontinued this type of transaction with CONSOL Energy in connection with the separation of the companies.

 

Land rental fees decreased in 2004 attributable to new agreements being put into place that allow fees to be recoupable against royalties owed. Prior period agreements did not include the recoupable feature.

 

Well plugging accretion expense increased in 2004 compared to 2003 due to higher well plugging liabilities, which increased due to additional wells being drilled.

 

Legal settlements in 2003 were related to a settlement paid for a royalty dispute. The claim alleged that CNX Gas calculated royalties owed to certain lessors using components that were not consistent with the agreement.

 

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Pursuant to the court-ordered settlement, CNX Gas paid the difference between CNX Gas’ calculation and the court-approved calculation for royalties on gas production from September 1999 to December 2002.

 

Miscellaneous costs and expenses decreased due to various miscellaneous transactions that occurred in both periods, none of which were individually material. The decrease in miscellaneous costs was offset, in part, by an increase of $274 in direct administrative costs related to gas operations. The increase in direct administrative costs was primarily attributable to an increase in staffing levels.

 

Equity in (earnings) loss of affiliates were lower in 2004 compared to 2003 due to the following:

 

     2004

    2003

  

Dollar

Variance


   

Percentage

Change


 

Buchanan Generation

   $ 915     $ 1,173    $ (258 )   (22.0 )%

Knox Energy

     1,535       1,644      (109 )   (6.6 )

Coalfield Pipeline

     (27 )     115      (142 )   (123.5 )
    


 

  


     

Total Equity in Loss of Affiliates

   $ 2,423     $ 2,932    $ (509 )   (17.4 )%
    


 

  


 

 

Buchanan Generation’s losses were lower in 2004 compared to 2003 primarily due to the unit being run for more megawatt hours in 2004 compared to 2003. This improvement was offset, in part, by increased fuel charges due to higher average gas sales prices in 2004 compared to 2003.

 

Knox Energy losses were lower in 2004 compared to 2003 primarily due to production increases at the joint venture. The CNX Gas portion of the joint venture production was approximately 230 mmcf in 2004 compared to approximately 93 mmcf in 2003. CNX Gas owns a 50% interest in this joint venture.

 

Equity in earnings of Coalfield Pipeline improved in 2004 compared to 2003 due primarily to increased volumes transported through their gathering system.

 

Selling, general and administrative costs have increased to $6,327 in 2004 from $3,194 in 2003, primarily due to higher charges for legal fees, accounting fees, payroll processing and other service costs.

 

Depreciation, depletion and amortization has decreased due to the following items:

 

     2004

   2003

  

Dollar

Variance


   

Percentage

Change


 

Production

   $ 22,353    $ 23,424    $ (1,071 )   (4.6 )%

Gathering

     10,536      10,176      360     3.5  
    

  

  


     

Total Depreciation, Depletion and Amortization

   $ 32,889    $ 33,600    $ (711 )   (2.1 )%
    

  

  


     

 

Depreciation, depletion and amortization was consistent in both 2004 and 2003. Production assets are depreciated using the units of production method. Units of production depreciation was based on higher gas volumes, offset by a lower rate due to increased reserve figures at January 1, 2004 compared to January 1, 2003. Gathering assets are depreciated using the straight-line method and did not materially change in the period-to- period comparison.

 

Income Taxes

 

     2004

    2003

    Variance

   

Percentage

Change


 

Earnings Before Income Taxes

   $ 132,686     $ 80,011     $ 52,675     65.8 %

Tax Expense

   $ 51,898     $ 31,202     $ 20,696     66.3 %

Effective Income Tax Rate

     39.1 %     39.0 %     0.1 %      

 

CNX Gas’ effective tax rate was consistent in 2004 and 2003.

 

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Cumulative Effect of Changes in Accounting for Gas Well Plugging Costs

 

Effective January 1, 2003, CNX Gas adopted SFAS No. 143 as required. CONSOL Energy reflected a gain of $2,905, net of a tax cost of approximately $1,879. At the time of adoption, total assets, net of accumulated depreciation, increased approximately $2,085 and total liabilities decreased approximately $2,699. The amounts recorded upon adoption are dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rate.

 

Previous accounting standards generally used the units-of-production method to match estimated retirement costs with the revenues generated by the producing assets. In contrast, SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines. Because of the long lives of the underlying producing assets, the impact on net income in the near term is not expected to be material.

 

Critical Accounting Policies

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities in the consolidated financial statements and at the date of the financial statements, as well as the reported amounts of income and expenses during the reporting period. Note 1 of the notes to the consolidated annual financial statements included in this Annual Report describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.

 

Other Post Employment Benefits

 

CNX Gas participates in certain CONSOL Energy sponsored benefit plans which provide medical and life benefits to employees that retire with at least twenty years of service and have attained age 55 or fifteen years of service and have attained age 62. Additionally, any salaried employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree medical and life benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of $1,000 per year of service at retirement. In addition to the change in eligibility requirements, other changes have been made to the medical plan which covers eligible salaried employees and retirees. These changes include a cost sharing structure where essentially all participants contribute a minimum of 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan participants. CNX Gas does not expect to contribute to the other post employment benefit plan in 2006. CNX Gas expects to pay benefit claims as they become due.

 

Various actuarial assumptions, including discount rate, expected trend in health care costs, average remaining service period, average remaining life expectancy and per capita costs, are used by CONSOL Energy’s independent actuary to estimate the cost and benefit obligations for our retiree health plans. The discount rate is determined each year at the measurement date (currently September 30). The discount rate is an estimate of the current interest rate at which the Other Post Employment Benefit liabilities could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. For the year ended December 31, 2005 and 2004, the discount rate used to calculate the period end liability and the following year’s expense was 5.75% and 6.00%, respectively.

 

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Salaried Pensions

 

As of December 31, 2005, CNX Gas participates in a non-contributory defined benefit retirement plan, administered by CONSOL Energy, covering substantially all salaried employees. The pension benefit obligation earned by salaried CNX Gas employees prior to the date of separation from CONSOL Energy remains with CONSOL Energy. As of the date of separation, any incremental pension liability earned by CNX Gas salaried employees is the obligation of CNX Gas. The benefits for this plan are based primarily on years of service and employees’ compensation near retirement. Effective January 1, 2006, an amendment was made to the CONSOL Energy Inc. Employee Retirement Plan that suspended all service accruals of gas employees in this plan. In its place, an identical plan was created sponsored by CNX Gas to provide a benefit for all service accruals going forward.

 

Reserve Estimates

 

Our estimates of proved natural gas reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of our proved natural gas reserves are inherently imprecise. Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves may vary substantially from our estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

 

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 exploring for, acquiring and developing oil and natural gas reserves. The successful efforts method allows only for the capitalization of costs directly associated with exploring for, acquiring and developing proven natural gas properties. Costs related to exploration that are not successful are expensed when it is determined that commercially productive gas reserves were not found. We have elected to use the successful efforts method to account for our gas producing activities.

 

Contingencies

 

CNX Gas is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. We do not believe these proceedings will have a material adverse effect on our consolidated financial position. It is possible, however, that future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the effectiveness of our strategies related to these proceedings.

 

Deferred Taxes

 

CNX Gas accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2005, CNX Gas had deferred tax liabilities in excess of deferred tax assets of approximately $38

 

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million. The deferred tax asset components are evaluated periodically to determine if a valuation allowance is necessary. No valuation allowance has been recognized because CNX Gas has determined that it is more likely than not that all of these deferred tax assets will be realized.

 

Well Plugging Obligations

 

SFAS No. 143 requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations relate to the closure of gas wells upon exhaustion of gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the gas well closing liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

 

SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.

 

Liquidity and Capital Resources

 

We intend to satisfy our future working capital requirements and fund our capital expenditures with cash from operations and our recently entered into $200 million credit facility. CNX Gas entered into a new credit agreement dated as of October 7, 2005, which is described in more detail below, with a group of commercial lenders. The new credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200 million (with the ability to request an increase in the aggregate outstanding principal amount up to $300 million), including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital.

 

CNX Gas and our subsidiaries had guaranteed CONSOL Energy’s $750 million revolving credit facility and 7.875% notes due March 1, 2012 in the principal amount of approximately $250 million. In addition, the assets of CNX Gas’ subsidiaries as well as substantially all of the assets being contributed to CNX Gas by CONSOL Energy were subject to liens securing this revolving credit facility, the 7.875% notes and CONSOL Energy’s 8.25% medium term notes due 2007 in the principal amount of approximately $45 million. Lastly, the principal gas subsidiary participated and sold receivables in CONSOL Energy’s $125 million receivables facility. CONSOL Energy obtained the release of CNX Gas and our subsidiaries from these guarantees in connection with the separation of the companies as well as the release of these liens on the assets of the CNX Gas subsidiaries and the other assets being contributed to CNX Gas and terminated the participation of the principal gas subsidiary in CONSOL Energy’s receivables facility. Although released from the existing guarantee of the 7.875% notes, the indenture for the 7.875% notes requires CNX Gas to guarantee the 7.875% notes if CNX Gas entered into borrowing arrangements with one or more third parties (excluding CONSOL Energy). As a result of entering into our new $200 million credit agreement with third party commercial lenders, we and our subsidiaries executed a supplemental indenture and are guarantors of the 7.875% notes. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture and the agreement governing the 8.25% medium term notes would require CNX Gas to ratably secure both the 7.875% notes and the 8.25% medium term notes. CONSOL Energy has advised us that, in accordance with its previously stated intention, CONSOL Energy sought to obtain an amendment to its indenture for the 7.875% notes in order to obtain the release of CNX Gas and our subsidiaries as guarantors of the 7.875% notes. Based on its discussions with a number of the note holders, CONSOL Energy has determined that, at this time, it cannot obtain an amendment of the indenture on commercially acceptable terms. Therefore, CONSOL Energy will not formally solicit the 7.875% note holders for the release and, consequently, we will remain guarantors of the 7.875% notes.

 

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We believe that cash generated from operations and borrowings under our new credit facility will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), and to provide required financial resources. Nevertheless, our ability to satisfy our working capital requirements or fund planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the gas industry and other financial and business factors, some of which are beyond our control.

 

We have also entered into various gas swap transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net loss of $34.4 million (net of $22.3 million of deferred tax) at December 31, 2005. The ineffective portion of the changes in the fair value of these contracts was insignificant to earnings for the twelve months ended December 31, 2005.

 

Cash Flows

 

    

2005

Year to

Date


   

2004

Year to

Date


    Change

 

Cash provided by operating activities

   $ 144,997     $ 175,350     $ (30,353 )

Cash used in investing activities

   $ (108,287 )   $ (93,114 )   $ (15,173 )

Cash used in financing activities

   $ (16,640 )   $ (82,237 )   $ 65,597  

 

CNX Gas is no longer part of CONSOL Energy’s accounts receivable securitization program, which historically resulted in a quick turnaround. The receivables we generate now remain with CNX Gas, and the cash is collected in each subsequent month.

 

Contractual Commitments

 

The following is a summary of our significant contractual obligations at December 31, 2005 (in thousands). We estimate payments related to these items, net of any applicable reimbursements, related to these items at December 31, 2005 to be as follows:

 

(In thousands)


  

Within

1 Year


   1-3
Years


   3-5
Years


  

More than

5 Years


   Total

Long Term Debt Obligations

   $ —      $ —      $ —      $ —      $ —  

Capital (Finance) Lease Obligations

     3,658      12,753      11,173      39,506      67,090

Operating Lease Obligations

     372      380      257      905      1,914

Other Long-Term Liabilities:

                                  

Gas Firm Transportation Obligation

     2,847      4,621      4,621      3,856      15,945

Other Liabilities (a)

     —        —        —        12,096      12,096

Well Plugging Liabilities

     378      756      756      9,018      10,908

Pension

     1      8      35      175      219

Postretirement Benefits Other than Pension

     5      44      104      3,215      3,368
    

  

  

  

  

Total Contractual Obligations

   $ 7,261    $ 18,562    $ 16,946    $ 68,771    $ 111,540
    

  

  

  

  


(a) This item represents legal contingencies reflected on the balance sheet for potential settlements of the two cases referenced in Note 18 of our annual financial statements. Due to the uncertainty surrounding these settlements, it is difficult to predict if and when a payout may take place.

 

As discussed in “Critical Accounting Policies” and in the Notes to our Consolidated Financial Statements included in this Annual Report, our determination of these long-term liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated.

 

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Moreover, in particular, for periods after 2005 our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions.

 

$200 Million Credit Facility.

 

We and our wholly-owned subsidiaries entered into a new credit agreement dated as of October 7, 2005 with a group of commercial lenders. The new credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200 million (with the ability to request an increase in the aggregate outstanding principal amount up to $300 million), including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. In connection with the closing of the credit agreement, a $50 million intercompany credit agreement with CONSOL Energy was terminated.

 

Our ability to borrow and obtain letters of credit under the new credit agreement is generally limited to a borrowing base. The required number of lenders will determine this borrowing base by calculating a loan value of CNX Gas’ proved reserves and reducing that number by an equity cushion determined by these lenders.

 

Interest on outstanding indebtedness under the credit agreement currently accrues, at our option, at a rate based on either: (A) the greater of (i) the lead bank’s prime corporate lending rate and (ii) the federal funds open rate plus 0.5%, in each case, plus a margin ranging from 0% to 0.25%, or (B) the LIBOR rate plus a margin ranging from 1.00% to 1.75%. The applicable margin added to the underlying interest rate fluctuates based on the aggregate outstanding principal under the credit agreement with the margin increasing as the outstanding principal amount increases.

 

The new credit agreement matures on October 7, 2010, and requires compliance with conditions precedent that must be satisfied prior to any borrowing as well as ongoing compliance with certain affirmative and negative covenants to which CNX Gas and its wholly-owned subsidiaries must adhere. The affirmative covenants include (i) maintenance of existence, (ii) payment of obligations, including taxes, (iii) maintenance of properties, insurance, intellectual property and books and records, (iv) compliance with laws, leases, pipeline arrangements and other material contractual obligations, (v) use of proceeds, (vi) subordination of intercompany loans and (vii) access to title information. The negative covenants include, without limitation, restrictions (in each case with certain limited exceptions unless otherwise noted) on the ability of CNX Gas and its wholly-owned subsidiaries to:

 

    create, incur, assume or suffer to exist any indebtedness;

 

    create or permit to exist liens on its properties;

 

    guaranty the debt of another party except in certain circumstances (which exception includes our guarantee of CONSOL Energy’s $250 million 7.875% notes due 2012);

 

    merge with or into another person, liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets (other than similar lines of business for total consideration below specified amounts);

 

    make particular investments and loans;

 

    sell, transfer, convey, assign or dispose of its assets or properties other than in the ordinary course of business and other select instances;

 

    deal with any affiliate except in the ordinary course of business on terms no less favorable to us than we would otherwise receive in an arm’s length transaction;

 

    other than CNX Gas, issue additional equity to any person other than CNX Gas or its wholly-owned subsidiaries;

 

    amend in any material manner its certificate of incorporation, bylaws, or other organizational documents;

 

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    enter into an agreement that prohibits the granting of a lien on our property or the property of any of our wholly-owned subsidiaries;

 

    enter into any hedging agreement other than those permitted by the credit agreement in the ordinary course of our business; or

 

    voluntarily sell, pool or unitize its proved reserves.

 

The new credit agreement also requires us to maintain certain financial ratios calculated as of the end of each fiscal quarter: the ratio of outstanding indebtedness (less cash on hand) to consolidated earnings before interest, taxes, depreciation and amortization is required to be equal to or less than three to one and the ratio of consolidated earnings before interest, taxes, depreciation and amortization to consolidated cash interest expense is required to be equal to or greater than three to one. The new credit agreement also contains customary events of default, including a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants.

 

In addition, the new credit agreement restricts our ability to make or pay dividends or distributions to our stockholders. We cannot make or pay dividends or distributions to our stockholders unless (i) the aggregate amount does not exceed fifty percent of our consolidated net income from the preceding four quarters and (ii) at the time of payment after giving effect thereto, our outstanding indebtedness (less cash on hand) is less than or equal to our consolidated earnings before interest, taxes, depreciation and amortization, and our outstanding borrowings under the credit agreement do not exceed 75 percent of the then current total availability under the facility or the borrowing base (whichever is less) and no default or potential default exists.

 

Our obligations under the new credit agreement are not secured by a lien on any of our assets. Our wholly-owned subsidiaries guaranteed our obligations.

 

Off-Balance Sheet Arrangements

 

We do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are likely to have a material current or future effect on our condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to the consolidated financial statements.

 

Recent Accounting Pronouncements

 

In September 2005, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single non-monetary transaction subject to the fair value exception of APB Opinion No. 29. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. The rules apply to new arrangements entered into in reporting periods beginning after March 15, 2006. The accounting for transactions that CNX Gas considers matching buy/sell transactions will be affected by this consensus and therefore, upon adoption, these transactions will no longer be recorded on a gross basis. CNX Gas is currently studying the provisions of this consensus to determine the impact on its consolidated financial statements; however, management does not believe any impact on net income would be material. There will be no impact on cash flows from operations as a result of adoption.

 

In June 2005, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 154, Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3.

 

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This Statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This Statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. The correction of an error in previously issued financial statements is not an accounting change. However, the reporting of an error correction involves adjustments to previously issued financial statements similar to those generally applicable to reporting an accounting change retrospectively. Therefore, the reporting of a correction of an error by restating previously issued financial statements is also addressed by this Statement. This Statement shall be effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We do not expect this guidance to have a significant impact on CNX Gas.

 

In April 2005, the FASB issued FSP No. FAS 19-1 “Accounting for Suspended Well Costs” (FSP 19-1). This position concluded that exploratory well costs should continue to be capitalized beyond twelve months when the well has found a sufficient quantity of reserves to justify its completion as a producing well, and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. This guidance requires management to exercise more judgment than was previously required and also requires additional disclosure. Management does not believe this statement of position will have a significant effect on the financial statements.

 

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. This interpretation clarifies that the term, conditional asset retirement obligation, as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred, generally upon acquisition, construction, or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. SFAS No. 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. We do not expect this guidance to have a significant impact on CNX Gas.

 

On December 15, 2004, the FASB released its final revised standard entitled FASB Statement No. 123R, “Share-Based Payment” (SFAS No.123R). This Statement requires that all public entities measure the cost of equity-based service awards based on the grant-date fair value. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award or the requisite service period, which usually is the vesting period. Compensation cost is not recognized for equity instruments for which employees do not render the requisite service. In addition, the SEC Staff issued Staff Accounting Bulletin (SAB) 107 on SFAS No. 123R in March 2005. The SAB was issued to assist preparers by simplifying some of the implementation challenges of SFAS No. 123R while enhancing information that investors receive. This SAB provides guidance related to, among other relevant items, share-based payment transactions with non-employees, valuation methods, the classification of compensation expense, non-GAAP financial measures, first-time adoptions of SFAS No.123R in an interim period, capitalization of compensation cost related to share-based payment arrangements, the accounting for income tax effects, the modification of employee share options prior to adoption of SFAS No. 123R, and disclosures in Management’s Discussion and Analysis subsequent to adoption of SFAS No. 123R. SFAS No.123R is to be effective for public companies as of the beginning of the first annual reporting period that begins after June 15, 2005. CNX Gas will implement SFAS No. 123R on January 1, 2006, as required. The expected impact of unvested stock options outstanding at December 31, 2005,

 

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under the modified prospective application, is approximately a $1.4 million reduction to earnings before income taxes for the year ended December 31, 2006. Management is currently evaluating the policy for determining our windfall tax benefits.

 

In October 2004, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-10, “Applying Paragraph 19 of FASB Statement No. 131, ‘Disclosure about Segments of an Enterprise and Related Information,’ in Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds” (EITF 04-10). FASB Statement No. 131 requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. EITF 04-10 clarifies how an enterprise should evaluate the aggregation criteria in paragraph 17 of FAS No. 131 when determining whether operating segments that do not meet the quantitative thresholds may be aggregated in accordance with paragraph 19 of FAS No. 131. In addition, the FASB Task Force has requested that the FASB staff propose a FASB Staff Position (FSP) to provide guidance in determining whether two or more operating segments have similar economic characteristics. The Task Force has agreed that since the two issues are interrelated, the effective date of EITF 04-10 should coincide with the future undetermined effective date of the anticipated FSP. We are currently evaluating the positions addressed in EITF 04-10, and foresee no significant changes in the reporting practices currently used to report segment information.

 

In October 2004, the American Jobs Creation Act of 2004 was signed into law. CNX Gas has implemented the qualified production activities deduction as enacted by the American Jobs Creation Act of 2004. The deduction is currently equal to 3% of qualified production activities income as limited by taxable income and as limited by 50 percent of the employer’s W-2 wages for the tax year. The percentage used in computing the deduction will be 3% in 2006, 6% in 2007 through 2009 and 9% in 2010 and after. As a special deduction in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” it is included as a permanent benefit in our estimate of our annual effective tax rate.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

 

In addition to the risks inherent in our operations, CNX Gas is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CNX Gas’ exposure to the risks of changing natural gas prices.

 

CNX Gas uses fixed-price contracts and derivative commodity instruments that qualify as cash-flow hedges under Statement of Financial Accounting Standards No. 133, as amended, to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy strictly prohibits the use of derivatives for speculative positions.

 

CNX Gas has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from our asset base. All of the derivative instruments are held for purposes other than trading. They are used primarily to reduce uncertainty and volatility and cover underlying exposures. CNX Gas’ market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

 

CNX Gas believes that the use of derivative instruments along with the risk assessment procedures and internal controls does not expose CNX Gas to material risk. However, the use of derivative instruments without other risk assessment procedures could materially affect CNX Gas’ results of operations depending on interest rates, exchange rates or market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.

 

For a summary of accounting policies related to derivative instruments, see Note 1 of the notes to the consolidated annual financial statements included in this Annual Report.

 

Sensitivity analyses of the incremental effects on pre-tax income for the twelve months ended December 31, 2005 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of December 31, 2005 are provided in the following table:

 

     Incremental Decrease Assuming a
Hypothetical Price Decrease of:


                 10%            

               25%            

     (In millions)

Pre-Tax Income (1)

   $ 34.4    $ 75.5

(1) CNX Gas remains at risk for possible changes in the market value of these derivative instruments; however, such risk should be reduced by price changes in the underlying hedged item. The effect of this offset is not reflected in the sensitivity analyses. CNX Gas entered into derivative instruments to convert the market prices related to portions of the 2005 through 2008 anticipated sales of natural gas to fixed prices. The sensitivity analyses reflect an inverse relationship between increases in commodity prices and a benefit to earnings. When commodity prices increase, pretax income decreases. As of December 31, 2005, the fair value of these contracts was a net loss of $34.4 million (net of $22.3 million deferred tax). We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

 

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Hedging Volumes

 

As of December 31, 2005, our hedged volumes for the periods indicated are as follows:

 

   

Three Months
Ended

March 31,


  Three Months
Ended
June 30,


  Three Months
Ended
September 30,


  Three Months
Ended
December 31,


  Total Year

2006 Fixed Price Volumes

                             

Hedged mcf

    3,654,822     4,619,289     4,670,051     4,050,761     16,994,923

Weighted Average Hedge Price/mcf

  $ 6.88   $ 7.73   $ 7.73   $ 7.21   $ 7.42

2007 Fixed Price Volumes

                             

Hedged mcf

    1,827,411     1,847,717     1,868,020     1,868,020     7,411,168

Weighted Average Hedge Price/mcf

  $ 7.67   $ 7.67   $ 7.67   $ 7.67   $ 7.67

2008 Fixed Price Volumes

                             

Hedged mcf

    1,847,716     1,847,716     1,868,020     1,868,020     7,431,472

Weighted Average Hedge Price/mcf

  $ 7.20   $ 7.20   $ 7.20   $ 7.20   $ 7.20

 

CNX Gas is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review.

 

All of CNX Gas’ transactions are denominated in U.S. dollars, and, as a result, we do not have material exposure to currency exchange-rate risks.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Financial Statements for the Twelve Months Ended December 31, 2005, 2004 and 2003

    

Report of Independent Registered Public Accounting Firm

   63

Consolidated Statements of Income

   64

Consolidated Balance Sheets

   65

Consolidated Statements of Stockholders’ Equity

   66

Consolidated Statements of Cash Flows

   67

Notes to Audited Financial Statements

   68

 

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Report of Independent Registered Public Accounting Firm

 

To the Board of Directors and Stockholders of CNX Gas Corporation:

 

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of CNX Gas Corporation and its subsidiaries (CNX Gas) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of CNX Gas’ management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in Note 5 to the consolidated financial statements, CNX Gas changed the manner in which it accounts for asset retirement costs as of January 1, 2003.

 

/s/    PricewaterhouseCoopers LLP

 

Pittsburgh, Pennsylvania

February 20, 2006

 

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CNX GAS CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)

 

     For the Twelve Months Ended December 31,

     2005

   2004

   2003

Revenue and Other Income:

                    

Outside Sales

   $ 322,382    $ 256,579    $ 178,326

Related Party Sales

     6,052      22,036      32,572

Purchased Gas Sales

     275,148      112,005      —  

Other Income

     9,859      6,916      4,485
    

  

  

Total Revenue and Other Income

     613,441      397,536      215,383
    

  

  

Costs and Expenses:

                    

Lifting Costs

     26,794      23,939      20,761

Gathering and Compression Costs

     40,623      37,021      28,914

Royalty

     36,641      32,914      24,200

Purchased Gas Costs

     278,720      113,063      —  

Other

     21,147      16,274      21,771

Equity in Loss of Affiliates

     149      2,423      2,932

Selling, General and Administrative

     7,596      6,327      3,194

Depreciation, Depletion and Amortization

     35,039      32,889      33,600

Interest Expense

     14      —        —  
    

  

  

Total Costs and Expenses

     446,723      264,850      135,372
    

  

  

Earnings Before Cumulative Effect of Change in Accounting Principle and Income Taxes

     166,718      132,686      80,011

Income Taxes

     64,550      51,898      31,202
    

  

  

Earnings Before Cumulative Effect of Change in Accounting Principle

     102,168      80,788      48,809

Cumulative Effect of Change in Accounting For Gas Well Closing Costs (Net of Income Taxes of $1,879)

     —        —        2,905
    

  

  

Net Income

   $ 102,168    $ 80,788    $ 51,714
    

  

  

Earnings per share:

                    

Basic

   $ 0.76    $ 0.66    $ 0.42
    

  

  

Diluted

   $ 0.76    $ 0.66    $ 0.42
    

  

  

Weighted Average Number of Common Shares Outstanding:

                    

Basic

     134,071,334      122,896,667      122,896,667
    

  

  

Dilutive

     134,137,219      122,988,359      122,988,359
    

  

  

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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CNX GAS CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

     December 31,

 
     2005

    2004

 

ASSETS

                

Current Assets:

                

Cash and Cash Equivalents

   $ 20,073     $ 3  

Accounts Receivable:

                

Trade

     41,121       700  

Related Party

     728       —    

Other

     550       735  

Deferred Taxes

     9,339       8,301  

Derivatives

     —         3,766  

Other Current Assets

     18,067       6,585  
    


 


Total Current Assets

     89,878       20,090  

Property and Equipment, Net

     723,547       640,876  

Other Assets

     11,903       14,951  

Investments in Equity Affiliates

     49,528       47,373  
    


 


TOTAL ASSETS

   $ 874,856     $ 723,290  
    


 


LIABILITIES AND STOCKHOLDERS’ EQUITY

                

Current Liabilities:

                

Accounts Payable

   $ 22,541     $ 24,002  

Accrued Royalties Payable

     10,504       8,701  

Accrued Severance Taxes

     2,747       2,337  

Accrued Income Taxes

     5,518       941  

Derivatives

     23,777       13,027  

Other Current Liabilities

     21,071       6,112  
    


 


Total Current Liabilities

     86,158       55,120  

Deferred Taxes

     47,736       183,624  

Other Liabilities

     14,310       10,202  

Well Plugging Liabilities

     10,908       8,685  

Derivatives

     32,909       —    

Postretirement Benefits Other Than Pension

     3,363       3,103  
    


 


Total Liabilities

     195,384       260,734  

Stockholders’ Equity

                

Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,833,334 Issued and Outstanding at December 31, 2005

     1,508       —    

Capital in Excess of Par Value

     779,509       215,710  

Retained Earnings (Deficit)

     (65,530 )     252,469  

Accumulated Other Comprehensive Loss

     (34,733 )     (5,623 )

Unearned Compensation on Restricted Stock Units

     (1,282 )     —    
    


 


Total Stockholders’ Equity

     679,472       462,556  
    


 


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 874,856     $ 723,290  
    


 


 

The accompanying notes are an integral part of these consolidated financial statements.

 

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CNX GAS CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands)

 

     Common
Stock


   Capital In
Excess of
Par Value


   

Retained

Earnings


   

Accumulated
Other

Comprehensive

Loss


   

Unearned

Compensation

on Restricted

Stock Units


   

Total

Stockholders’

Equity


 

Balance at December 31, 2002

   $ —      $ 350,473     $ 119,967     $ (1,823 )   $ —       $ 468,617  

Net Income

     —        —         51,714       —         —         51,714  

Gas Cash Flow Hedge (Net of $2,312 tax)

     —        —         —         (3,573 )(a)     —         (3,573 )
    

  


 


 


 


 


Comprehensive Income (Loss)

     —        —         51,714       (3,573 )     —         48,141  

Return of Capital to Parent

     —        (52,526 )     —         —         —         (52,526 )
    

  


 


 


 


 


Balance at December 31, 2003

     —        297,947       171,681       (5,396 )     —         464,232  

Net Income

     —        —         80,788       —         —         80,788  

Gas Cash Flow Hedge (Net of $146 tax)

     —        —         —         (227 )(b)     —         (227 )
    

  


 


 


 


 


Comprehensive Income (Loss)

     —        —         80,788       (227 )     —         80,561  

Return of Capital to Parent

     —        (82,237 )     —         —         —         (82,237 )
    

  


 


 


 


 


Balance at December 31, 2004

     —        215,710       252,469       (5,623 )     —         462,556  

Net Income

     —        —         102,168